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In the pre-Base F 2018 emission estimates, an energy efficiency factor was applied to energy 

related stationary area sources. The energy efficiency factor was applied along with the growth 

factor to account for both growth and changes in energy efficiency. That factor was not applied 

to the Base F projections since information supplied by U.S. EPA related to the CAIR growth 

factors indicated that growth values for those categories were derived from U.S. Department of 

Energy (DOE) and were felt to account for changes in growth and projected energy efficiency. 

For the Base G inventory, these energy efficiency factors were re-instituted and used in 

conjunction with EGAS 5.0 growth factors in a manner identical to that used for the pre-Base F 

inventories. The energy efficiency factors were derived from U.S. DOE’s Annual Energy 

Outlook report. 

One significant difference between the Base F and Base G control factors was for counties and 

independent cities in northern Virginia. Several counties and independent cities in northern 

Virginia are subject to Ozone Transport Commission rules. For these counties and independent 

cities, controls for portable fuel containers, mobile equipment repair/refinishing, consumer 

products, solvent metal cleaning, and the architectural and industrial maintenance rules 

were added. The counties/independent cities (FIPS code) included in the changes for Base G 

were: Alexandria City (51510), Arlington (51013), Fairfax City (51600), Fairfax (51059), Falls 

Church City (51610), Fredericksburg City (51630), Loudoun (51107), Manassas City (51683), 

Manassas Park City (51685), Prince William County (51153), Spotsylvania (51177), and 

Stafford (51179). Not all OTC rules applied to all counties/cities. 

2.2.1.2 Stationary area source growth 

As indicated above, growth factors for the Base F and Base G 2009 and 2018 inventories were 

obtained from the U.S. EPA and are linear interpolations of the growth factors used for the Clean 

Air Interstate Rule (CAIR) projections. The growth factors for the CAIR obtained by MACTEC 

were developed using a base year of 2001 and provided growth factors for 2010 and 2015. 

MACTEC used the TREND function in Microsoft ExcelTM to calculate 2002, 2009 and 2018 

values from the 2001, 2010 and 2015 values. The TREND function provides a linear 

interpolation of intermediate values from a known series of data points (in this case the 2001, 

2010 and 2015 values) based on the equation for a straight line. These values were calculated at 

the State and SCC level with the exception of paved road emissions (SCC = 2294000000). The 

growth factors for paved roads were available in the CAIR data set at the State, county and SCC 

level so they were applied at that level. 

Prior to utilizing the growth factors from the CAIR projections, MACTEC confirmed that all 

SCCs found in the VISTAS 2002 base year inventory were in the CAIR file (for Base F the 

starting point was the version 3.1 2002 base year inventory, for Base G the starting point was the 

Base F 2002 base year inventory). Some SCCs were not found in the CAIR file. For those SCCs, 
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the growth factors used were derived in one of five ways. First where possible, they were taken 

from a beta version of EGAS 5.0. In other cases, the growth factor was set to one (i.e., no 

growth). In other cases, a similar SCC that had a CAIR growth factor was used. In a few cases a 

growth factor based on an average CAIR growth at the 6 digit SCC level was calculated. Finally 

a number of records used population as the growth surrogate. For the Base G inventory, CAIR 

growth factors for fuel fired area sources were replaced with EGAS 5.0 growth factors (used in 

conjunction with AEO fuel efficiency factors). A comment field in the growth factor file was 

used to mark those records that were not taken directly from the CAIR projection growth factors. 

2.2.1.3 Differences between 2009/2018 

Methodologically, there was no difference in the way that 2009 and 2018 emissions were 

calculated for stationary area sources. The individual control and growth factors were different 

(due to the linear interpolation used to calculate the values) but the calculation methods were 

identical. This applies to both Base F and Base G. 

The only exception to this is for the State of North Carolina for Base G. North Carolina provided 

an emissions update file used to override calculated projections for a number of area source 

categories. The values in these files (provided for both 2009 and 2018) were used to overwrite 

the calculated projected emissions in the final NIF file. 

2.2.2 Agricultural area sources 

The general approach used to calculate projected emissions for agricultural area sources 

(predominantly NH3 emission sources) was as follows: 

1. MACTEC used the version 3.1 2002 base year inventory data (which was based on 

the CMU ammonia model version 3.6). 

2. MACTEC worked with the VISTAS States (via the Agricultural Sources SIWG) to 

obtain any State specific growth and/or future controls from the States for agricultural 

sources. 

3. Since the base year emissions were uncontrolled, and no future controls for these 

sources were identified, MACTEC projected the agricultural emissions using Statespecific growth if available, otherwise the U.S. EPA’s Interstate Air Quality 

Transport Rule (IAQTR)/Ammonia inventory was used to develop the growth factors 

used to project the revised 2002 base year inventory to 2009 or 2018. Since the 

IAQTR inventory was only used to construct growth factors rather than using the 

emissions directly, no updated growth factors were prepared from the CAIR 

inventory values. 
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4. MACTEC then provided the final draft inventory for review and comment by the 

VISTAS States. 

No change in the agricultural area source emission projections were made between Base F and 

Base G other than the removal of wild animal and human perspiration as a result of their removal 

from the 2002 base year file for Base G. 

2.2.2.1 Control assumptions for agricultural area sources 

No controls were identified either by the individual VISTAS States or in the information 

provided in the EPA’s IAQTR or CAIR Ammonia inventory documents. Thus all projected 

emissions for agricultural area sources represent simple growth with no controls. 

2.2.2.2 Growth assumptions for agricultural area sources 

Growth for several agricultural area source livestock categories was developed using the actual 

emission estimates developed by the EPA as part of the NEI. That work included projections for 

the years 2002, 2010, 2015, 2020, and 2030. The actual emissions themselves were not used 

other than to develop growth factors since the 2002 NEI upon which the growth projections were 

based was prepared prior to the release of the 2002 Census of Agriculture data which was 

included in the CMU model (version 3.6) used to develop the Base F 2002 VISTAS base year 

inventory. Thus VISTAS Agricultural Sources SIWG decided to use the NEI ammonia inventory 

projected emissions to develop the 2009 and revised 2018 growth factors used to project 

emission for VISTAS. Details on the NEI inventory and projections can be found at: 

http://www.epa.gov/ttn/chief/ap42/ch09/related/nh3inventorydraft_jan2004.pdf. The actual data 

files for the projected emissions can be found at: 

http://www.epa.gov/ttn/chief/ap42/ch09/related/nh3output01_23_04.zip. 

In order to use the NEI projected emissions as growth factors, several steps were required. These 

steps were as follows: 

1. NEI projected emissions were only available for the years 2002, 2010, 2015, 2020, 

and 2030, thus the first task was to calculate intermediate year emissions for 2009 and 

2018. These values were calculated based on linear interpolation of the existing data. 

2. Once the intermediate emissions were calculated, MACTEC developed emission 

ratios to provide growth factors for 2009 and 2018. Ratios of emissions were 

established relative to the 2002 NEI emissions. 

3. Once the growth factors were established, MACTEC then evaluated whether or not 

all agricultural SCCs within the revised 2002 base year inventory had corresponding 
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growth factors. MACTEC established that not all SCCs within the base year 

inventory had growth factors. These SCCs fell into one of two categories: 

b. SCCs that had multiple entries in the NEI but only a single SCC in the 2002 

VISTAS base year inventory. The NEI was established using a process model 

and for some categories of animals, emissions were calculated for several 

aspects of the process. The CMU model version 3.6 which was the basis for 

the VISTAS 2002 Base F inventory did not use a process model. As a 

consequence a mapping of SCCs in the NEI projections and corresponding 

SCCs in the CMU inventory was made and for those SCCs an average growth 

factor was calculated from the NEI projections for use with the corresponding 

SCC in the CMU based 2002 Base F inventory. 

c. There were also State, county, SCC trios in the 2002 VISTAS Base F 

inventory which had no corresponding emissions in the NEI files. For these 

instances, MACTEC first developed State level average growth factors from 

the NEI projections for use in growing these records. Even after developing 

State level average growth factors there were still some State/SCC pairs that 

did not have matching growth. For these records, MACTEC developed 

VISTAS regional average growth factors at the SCC level from the NEI data. 

1. Once all of the growth factors were developed, they were used to project the 

emissions to 2009 and 2018. Growth factors were first applied at the State, county 

and SCC level. Then remaining records were grown with the State/SCC specific 

growth factors. Finally, any remaining ungrown records were projected at the SCC 

level using the VISTAS regional growth factor. 

For the livestock categories, the NEI emission projections only had data for beef and dairy cattle, 

poultry and swine. Thus for other livestock categories and for fertilizers alternative growth 

factors were required. 

The growth factors for other livestock categories and fertilizers were obtained from growth 

factors used for the IAQTR projections made by the U.S. EPA. The methodology for these 

categories was identical to that used for dairy, beef, poultry and swine with the exception that 

State/SCC and VISTAS/SCC growth factors were not required for these categories since the 

IAQTR data contained State, county and SCC level growth factors. The IAQTR data provided 

growth factors for 1996, 2007, 2010, 2015 and 2020. Linear interpolation was used to develop 

the growth factors for the intermediate years 2009 and 2018 required for the 

VISTAS projections. 
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There were a few exceptions to the methods used for projecting agricultural sources for the 

VISTAS projections. These exceptions were: 

1. All swine emissions for North Carolina were maintained at 2002 levels for each 

projection year to capture a moratorium on swine production in that State. 

2. Ammonia growth factors for a few categories (mainly feedlots) were assigned to be 

the same as growth factors for PM emissions from the NEI projections. This 

assignment was made because the CMU model showed emissions from these 

categories but the NEI projections did not show ammonia emissions but did show PM 

emissions. 

3. No growth factors were found for horse and pony emissions. These emissions were 

held constant at 2002 levels. 

There was no change in this method between Base F and Base G. Thus Base F and Base G 

agricultural emissions are the same in each inventory. Future efforts on the agricultural emissions 

category should look at any changes made to the CMU model to reflect the model farm approach 

used by EPA in their inventory plus any updated growth factors that may be more recent than the 

EPA inventory used to develop growth estimates for Base F/G. 

2.2.2.2.1 Differences between 2009/2018 

Methodologically, there was no difference in the way that 2009 and 2018 emissions were 

calculated for agricultural area sources. The growth factors were different (due to the linear 

interpolation used to calculate the values) but the calculation methods were identical. In addition 

there was no difference between Base F and Base G for this category. Thus Base F and Base G 

agricultural emissions are the same in each inventory. 

Tables 2.2-1 show the differences between Base F and Base G emissions for all area sources 

(including agricultural sources but excluding fires) for the 2002 base year and 2009 and 2018 by 

State and pollutant. 
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Table 2.2-1 2002 Base Year Emissions and Percentage Difference for Base F and Base G 

(based on actual emissions). 

Actual Area 2002 - Base G 

State CO NH3 NOX PM10-PRI PM25-PRI SO2 VOC 

AL 83,958 58,318 23,444 393,588 56,654 52,253 182,674 

FL 71,079 37,446 28,872 443,346 58,878 40,491 404,302 

GA 108,083 80,913 36,142 695,414 103,794 57,559 299,679 

KY 66,752 51,135 39,507 233,559 45,453 41,805 95,375 

MS 37,905 58,721 4,200 343,377 50,401 771 131,808 

NC 345,315 161,860 36,550 280,379 64,052 5,412 237,926 

SC 113,714 28,166 19,332 260,858 40,291 12,900 161,000 

TN 89,828 34,393 17,844 212,554 42,566 29,917 153,307 

VA 155,873 43,905 51,418 237,577 43,989 105,890 174,116 

WV 39,546 9,963 12,687 115,346 21,049 11,667 60,443 

Base F 

AL 83,958 59,486 23,444 393,093 73,352 47,074 196,538 

FL 105,849 44,902 29,477 446,821 81,341 40,537 439,019 

GA 107,889 84,230 36,105 695,320 133,542 57,555 309,411 

KY 66,752 51,097 39,507 233,559 52,765 41,805 100,174 

MS 37,905 59,262 4,200 343,377 63,135 771 135,106 

NC 373,585 164,467 48,730 303,492 69,663 7,096 346,060 

SC 113,714 29,447 19,332 260,858 51,413 12,900 187,466 

TN 89,235 35,571 17,829 211,903 49,131 29,897 161,069 

VA 155,873 46,221 51,418 237,577 52,271 9,510 129,792 

WV 39,546 10,779 12,687 115,346 25,850 11,667 61,490 

Percentage Difference (negative values means Base G increased from Base F) 

AL 0.00% 1.96% 0.00% -0.13% 22.76% -11.00% 7.05% 

FL 32.85% 16.61% 2.05% 0.78% 27.62% 0.12% 7.91% 

GA -0.18% 3.94% -0.10% -0.01% 22.28% -0.01% 3.15% 

KY 0.00% -0.07% 0.00% 0.00% 13.86% 0.00% 4.79% 

MS 0.00% 0.91% 0.00% 0.00% 20.17% 0.00% 2.44% 

NC 7.57% 1.59% 24.99% 7.62% 8.05% 23.74% 31.25% 

SC 0.00% 4.35% 0.00% 0.00% 21.63% 0.00% 14.12% 

TN -0.67% 3.31% -0.09% -0.31% 13.36% -0.07% 4.82% 

VA 0.00% 5.01% 0.00% 0.00% 15.84% -1013.45% -34.15% 

WV 0.00% 7.57% 0.00% 0.00% 18.57% 0.00% 1.70% 
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Table 2.2-2 2009 Projection Year Emissions and Percentage Difference for Base F and 

Base G (based on actual emissions). 

Actual Area 2009 - Base G 

State CO NH3 NOX PM10-PRI PM25-PRI SO2 VOC 

AL 66,654 64,268 23,930 413,020 58,699 48,228 143,454 

FL 57,011 38,616 28,187 503,230 64,589 36,699 420,172 

GA 94,130 89,212 37,729 776,411 112,001 57,696 272,315 

KY 57,887 53,005 42,088 242,177 46,243 43,087 94,042 

MS 27,184 63,708 4,249 356,324 51,661 753 124,977 

NC 301,163 170,314 39,954 292,443 69,457 5,751 187,769 

SC 90,390 30,555 19,360 278,299 41,613 13,051 146,107 

TN 74,189 35,253 18,499 226,098 44,124 30,577 154,377 

VA 128,132 46,639 52,618 252,488 44,514 105,984 147,034 

WV 31,640 10,625 13,439 115,089 20,664 12,284 55,288 

Base F 

AL 68,882 65,441 26,482 411,614 76,248 17,818 157,405 

FL 101,356 46,950 31,821 507,515 90,487 52,390 462,198 

GA 103,579 92,838 38,876 776,935 146,691 57,377 294,204 

KY 64,806 53,023 42,122 242,345 54,397 40,779 94,253 

MS 37,161 64,289 4,789 356,516 65,321 637 125,382 

NC 332,443 173,187 53,550 317,847 75,570 7,607 252,553 

SC 95,826 31,966 20,852 278,852 54,230 12,945 176,104 

TN 82,196 36,578 19,148 225,650 51,753 29,787 160,265 

VA 133,738 49,173 53,344 252,924 54,587 10,619 120,022 

WV 37,704 11,461 13,816 115,410 25,835 12,156 57,082 

Percentage Difference (negative values means Base G increased from Base F) 

AL 3.24% 1.79% 9.64% -0.34% 23.02% -170.67% 8.86% 

FL 43.75% 17.75% 11.42% 0.84% 28.62% 29.95% 9.09% 

GA 9.12% 3.91% 2.95% 0.07% 23.65% -0.56% 7.44% 

KY 10.68% 0.03% 0.08% 0.07% 14.99% -5.66% 0.22% 

MS 26.85% 0.90% 11.27% 0.05% 20.91% -18.10% 0.32% 

NC 9.41% 1.66% 25.39% 7.99% 8.09% 24.41% 25.65% 

SC 5.67% 4.41% 7.16% 0.20% 23.27% -0.82% 17.03% 

TN 9.74% 3.62% 3.39% -0.20% 14.74% -2.65% 3.67% 

VA 4.19% 5.15% 1.36% 0.17% 18.45% -898.09% -22.51% 

WV 16.08% 7.29% 2.73% 0.28% 20.02% -1.06% 3.14% 
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Table 2.2-3 2018 Projection Year Emissions and Percentage Difference for Base F and Base 

G (based on actual emissions). 

Actual Area 2018 - Base G 

State CO NH3 NOX PM10-PRI PM25-PRI SO2 VOC 

AL 59,626 71,915 25,028 445,256 62,323 50,264 153,577 

FL 53,903 40,432 30,708 578,516 72,454 38,317 489,975 

GA 93,827 99,885 41,332 880,199 123,704 59,729 319,328 

KY 54,865 55,211 44,346 256,052 47,645 44,186 103,490 

MS 22,099 69,910 4,483 375,495 53,222 746 140,134 

NC 290,809 180,866 43,865 315,294 71,262 6,085 189,591 

SC 83,167 33,496 20,592 304,251 44,319 13,457 161,228 

TN 68,809 36,291 19,597 246,252 46,692 31,962 182,222 

VA 121,690 50,175 56,158 275,351 46,697 109,380 150,919 

WV 28,773 11,504 14,828 121,549 21,490 12,849 60,747 

Base F 

AL 63,773 73,346 28,754 445,168 82,449 49,975 168,507 

FL 100,952 49,889 35,047 582,832 101,872 59,413 533,141 

GA 105,059 103,911 42,260 880,800 163,925 61,155 342,661 

KY 65,297 55,356 45,597 256,544 57,110 42,326 102,117 

MS 36,425 70,565 5,230 375,931 68,338 831 139,419 

NC 327,871 184,167 60,073 345,275 85,018 8,273 234,207 

SC 89,343 35,082 22,467 304,940 58,441 13,517 196,946 

TN 81,242 37,812 20,928 245,893 55,712 31,047 188,977 

VA 129,037 53,023 56,668 275,790 58,141 11,479 128,160 

WV 36,809 12,390 15,079 121,964 27,088 13,450 62,164 

Percentage Difference (negative values means Base G increased from Base F) 

AL 6.50% 1.95% 12.96% -0.02% 24.41% -0.58% 8.86% 

FL 46.61% 18.96% 12.38% 0.74% 28.88% 35.51% 8.10% 

GA 10.69% 3.87% 2.20% 0.07% 24.54% 2.33% 6.81% 

KY 15.98% 0.26% 2.74% 0.19% 16.57% -4.40% -1.34% 

MS 39.33% 0.93% 14.28% 0.12% 22.12% 10.19% -0.51% 

NC 11.30% 1.79% 26.98% 8.68% 16.18% 26.45% 19.05% 

SC 6.91% 4.52% 8.34% 0.23% 24.16% 0.44% 18.14% 

TN 15.30% 4.02% 6.36% -0.15% 16.19% -2.95% 3.57% 

VA 5.69% 5.37% 0.90% 0.16% 19.68% -852.83% -17.76% 

WV 21.83% 7.15% 1.66% 0.34% 20.66% 4.46% 2.28% 

2.2.3 Changes to Prescribed Fire for 2009/2018 Base G 

Just prior to release of version 3.1 of the VISTAS inventory several Federal agencies indicated 

that they had plans for increased prescribed fire burning in future years and that the “typical” fire 

inventory would likely not adequately capture those increases (memo from Bill Jackson and 

Cindy Huber, August 13, 2004). However data were not readily available to incorporate those 

changes up through the Base F inventory. As a consequence MACTEC worked with Federal 

Land Managers to acquire the data necessary to provide 2009 and 2018 specific projections for 

the prescribed fire component of the Base G fire inventory. The 2009 and 2018 projections 

developed using the method described below are being used by VISTAS as the 2009 and 2018 
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base case inventories for all States except FL. For FL the supplied data from the FLMs is not 

being used as FL felt that their data adequately reflected current and future prescribed burning 

practices. The “typical” fire projection is the 2002 base prescribed fire projection. 

One of the biggest issues in preparing the projection was how best to incorporate the data. Two 

agencies submitted data: Fish and Wildlife Service (FWS) and Forest Service (FS). FWS 

submitted annual acreage data by National Wildlife Refuge (NWR) and county with estimates of 

acres burned per day for each NWR. FS provided fire-by-fire acreage estimates based on 

mapping projected burning acreage to current 2002 modeling days. However, FWS did not 

submit data for VISTAS original base year preparation process, thus there was no known FWS 

data in the 2002 actual or typical inventories. Thus MACTEC had to develop a method that 

could use the county level data submitted by FWS. 

In addition, despite the fact that the FS submitted fire-by-fire data for the 2002 actual inventory 

and had mapped the projections to current burn days in the 2002 actual inventory, MACTEC 

could not do a simple replacement of those records with the 2009/2018 projections. This 

situation was created because several VISTAS States run a prescribed fire permitting program. 

To avoid double counting, only State data was used in those States for the 2002 actual inventory. 

Thus there were no Federal data in those States since the Federal data could have potentially 

duplicated State-supplied prescribed fire data. In VISTAS States without permit programs, the 

FS supplied data for 2002 was used and those records were marked in database. Thus for those 

States, the FS supplied 2009/2018 data could be directly substituted for the 2002 data. 

The method used by MACTEC to include the FS data applied a county level data approach for 

FS data where a State had a prescribed fire permitting program and a fire-by-fire replacement for 

FS data in States without permit programs. MACTEC used a county level approach for all of the 

FWS data. The approach used for each data set is discussed below. 

For the FWS data MACTEC summed the annual acres burned supplied by the FWS across all 

NWRs in a county. We then subtracted out 2002 acreage for that county from the FWS projected 

acreage annual total to avoid double counting. The remaining acreage was then multiplied by 0.8 

to account for blackened acres instead of the total perimeter acres that were reported. The revised 

total additional FWS acreage was then added to the total county “typical” acreage to determine 

future acreage burned for either 2009 or 2018. MACTEC then allocated the increased acreage to 

current modeling days. The average daily acres burned data provided by FWS per NWR/county 

was used to allocate the acreage to the correct number of days required to burn all of the acres. 

Guidance supplied by FWS indicated that up to three times the average daily acres burned could 

potentially be allocated to any one day. Thus if the estimated acreage per day were 100 acres 

then up to 300 acres could actually be allocated to a particular day. This approach (use of up to 

three times the average daily acres burned) was used if there were an insufficient number of 2002 
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modeling days available to account for all of the acreage increase. MACTEC used an 

incremental approach to using the increase above the base average daily acres. First we used 

twice the average daily acreage if that was sufficient to completely allocate the increased acreage 

over the total number of days available. If that wasn’t sufficient then we used three times the 

average daily acres burned to allocate the acreage. We applied the highest increases to days in 

the database that already had the highest acreage burned since we felt those days were most 

likely to represent days with representative conditions for conducting prescribed burns. 

The approach used by MACTEC for the FS was slightly different. For States that had permit 

programs, we used similar approach to the FWS county level approach. First we summed the FS 

data at county level, we then added that value to the typical acreage and then we allocated the 

acres to current modeling days. The mapping to current modeling days was performed by Bill 

Jackson of the USFS and provided to MACTEC. For States that do not have a prescribed fire 

permit program, MACTEC simply replaced the current fire-by-fire records in the database with 

fire-by-fire records from the FS and recalculated emissions based on fuel model and fuel loading. 

We also applied the same 0.8 correction for blackened acres applied to all FS supplied acreage as 

the supplied values represented perimeter acres. 

An additional problem with developing year-specific prescribed fire projections was how to 

adequately capture the temporal profile for those fires. In the 2002 actual fire inventory, fires 

occur on same days as state/FLM records. In the 2002 “typical” year inventory, fire acreage 

increased or decreased from acreage on the same fire days as were in the 2002 actual inventory, 

since the acres were simply increased for each day based on a multiplier used to convert from 

actual to typical. 

When prescribed fires acreage was added to a future year, MACTEC added acreage to individual 

fire days proportional to the annual increase (if acreage on a day is 10 percent of annual, add 10 

percent of projected increase to that same day). 

The table below shows how the FWS data for Okefenokee NWR were allocated for 2009 for 

Clinch County (Okefenokee NWR is located in four different counties). You can see that the 

total additional acres for the Clinch County portion of Okefenokee NWR was 1,956 acres. Two 

hundred eighty (280) acres were the estimated average daily acres burned for that NWR/county 

combination. Thus to allocate the entire 1,956 acres would require almost 7 burn days (1,956 

divided by 280). However only 5 burn days were found for Clinch County in the 2002 actual fire 

database. Thus we allocated twice the average acreage to the burn day with the most acres 

burned in the 2002 actual fire database (since our method allowed us to increase the average 

daily acres burned up to three times the recommended level). Thus the first burn day received 

560 acres and all others received 280 except the final day which received 276 to make the total 

equal to the required 1,956 acres. The table also indicates that the increased acres burned 
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0

2000

4000

6000

8000

10000

12000

14000

16000

1/1/2002

2/1/2002

3/1/2002

4/1/2002

5/1/2002

6/1/2002

7/1/2002

8/1/2002

9/1/2002

10/1/2002

11/1/2002

12/1/2002

Date of Fire Event

Acres

Typical

FWS Add

USFS Add

provided increases of from 10-48 percent in the acres burned on the individual burn days and an 

average of approximately 14 percent for the year as a whole. 

CLINCH COUNTY 3/1/2002 4/1/2002 2/1/2002 1/1/2002 11/1/2002 12/1/2002 

Total 

Annual

Acres (typical) 3,757 2,612 1,996 1,801 616 472 11,764

Add on FWS Projection 560 280 280 280 280 276 1,956

Total 4,316 2,891 2,276 2,080 895 747 13,720

Percent Increase 14.9% 10.7% 14.0% 15.6% 45.5% 58.5% 14.3%

The figure below shows the increases for prescribed burning in the four counties that comprise 

the Okefenokee NWR area (which also includes FS land). In this figure you can see the 

additional acreage added for the burn days from FWS and the individual day increases caused by 

projected increases in prescribed burning based on FS data. It should be noted that while the 

emissions represent 2009, all fire event dates listed are for 2002 to match up with the base year 

meteorology used in modeling exercises. 

Table 2.2-4 shows the percentage difference between the 2009 and 2018 projections developed 

for Base F and Base G. Base G includes the revised prescribed burning estimates described 

above. Values are calculated using Base F as the basis for change, thus negative values imply an 

increase in emissions for Base G. 

Figure 2.2-1 Prescribed Fire Projection for Okeefenokee NWR for 2009 
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Table 2.2-4 Percentage Difference Between Base F and Base G Fire Emissions by State 

State CO NH3 NOX PM10-PRI PM25-PRI SO2 VOC CO NH3 NOX PM10-PRI 

2009 Fires Base G 2018 Fires Base G AL 534,873 2,050 11,901 52,851 46,543 2,681 27,502 535,658 2,054 11,918 52,927 FL 923,310 3,157 19,791 98,470 88,756 4,129 51,527 923,310 3,157 19,791 98,470 GA 637,177 2,229 14,243 63,973 57,116 2,914 34,710 637,177 2,229 14,243 63,973 KY 31,810 143 682 3,093 2,653 187 1,497 33,296 150 714 3,237 MS 48,160 217 1,033 4,683 4,016 283 2,266 50,037 225 1,073 4,865 NC 96,258 433 2,065 9,359 8,027 566 4,530 111,266 501 2,387 10,819 SC 282,307 1,039 5,899 29,153 25,955 1,359 16,045 282,307 1,039 5,899 29,153 TN 17,372 78 373 1,689 1,449 102 817 18,860 85 405 1,834 VA 21,130 95 453 2,054 1,762 124 994 26,923 121 578 2,618 WV 3,949 18 85 384 329 23 186 5,013 23 108 487 2009 Fires Base F 2018 Fires Base F 

AL 514,120 1,957 11,456 50,833 44,812 2,559 26,526 514,120 1,957 11,456 50,833 FL 923,310 3,157 19,791 98,470 88,756 4,129 51,527 923,310 3,157 19,791 98,470 GA 620,342 2,153 13,882 62,336 55,712 2,815 33,918 620,342 2,153 13,882 62,336 KY 56,686 110 1,460 6,667 6,310 136 3,338 56,686 110 1,460 6,667 MS 128,471 177 3,328 14,693 13,680 100 13,625 128,471 177 3,328 14,693 NC 200,564 324 5,005 20,488 19,491 423 12,499 200,564 324 5,005 20,488 SC 253,005 908 5,270 26,304 23,511 1,187 14,666 253,005 908 5,270 26,304 TN 78,370 46 2,232 8,875 8,730 59 5,153 78,370 46 2,232 8,875 VA 19,159 159 978 18,160 17,361 99 912 19,159 159 978 18,160 WV 32,656 12 944 3,276 3,239 16 2,184 32,656 12 944 3,276 

Percentage Difference (negative number means an increase in Base G emissions) 

AL -4.04% -4.77% -3.89% -3.97% -3.86% -4.77% -3.68% -4.19% -4.95% -4.03% -4.12% FL 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% 0.00% GA -2.71% -3.52% -2.60% -2.63% -2.52% -3.52% -2.34% -2.71% -3.52% -2.60% -2.63% KY 43.88% -29.52% 53.25% 53.61% 57.96% -37.90% 55.15% 41.26% -35.57% 51.07% 51.44% MS 62.51% -22.07% 68.95% 68.13% 70.64% -183.85% 83.37% 61.05% -26.83% 67.74% 66.89% NC 52.01% -33.75% 58.74% 54.32% 58.82% -33.75% 63.76% 44.52% -54.60% 52.31% 47.19% SC -11.58% -14.52% -11.93% -10.83% -10.39% -14.52% -9.40% -11.58% -14.52% -11.93% -10.83% TN 77.83% -69.40% 83.30% 80.97% 83.41% -74.42% 84.14% 75.93% -83.92% 81.87% 79.34% VA -10.29% 40.36% 53.67% 88.69% 89.85% -25.40% -9.03% -40.53% 24.00% 40.97% 85.59% WV 87.91% -48.65% 91.03% 88.28% 89.83% -49.46% 91.49% 84.65% -88.70% 88.61% 85.12% 
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2.2.4 Quality Assurance steps 

Throughout the inventory development process, quality assurance steps were performed to 

ensure that no double counting of emissions occurred, to ensure that a full and complete 

inventory was developed for VISTAS, and to make sure that projection calculations were 

working correctly. Quality assurance was an important component to the inventory development 

process and MACTEC performed the following QA steps on the stationary and agricultural area 

source components of the 2009 and revised 2018 projection inventories: 

1. All final files were run through EPA’s Format and Content checking software. 

2. SCC level emission summaries were prepared and evaluated to ensure that emissions 

were consistent and that there were no missing sources. 

3. Tier comparisons (by pollutant) were developed between the 2002 base year 

inventory and the 2009 and 2018 projection inventories. In addition, total VISTAS 

pollutant summaries were prepared to compare total emissions by pollutant between 

versions of the inventory (e.g., between Base F and Base G). 

4. Data product summaries were provided to both the VISTAS Emission Inventory 

Technical Advisor and to the SIWG representatives for review and comment. 

Changes based on these comments were implemented in the files. 

5. Version numbering was used for all inventory files developed. The version 

numbering process used a decimal system to track major and minor changes. For 

example, a major change would result in a version going from 1.0 to 2.0. A minor 

change would cause a version number to go from 1.0 to 1.1. Minor changes resulting 

from largely editorial changes would result in a change from 1.00 to 1.01. 

2.3 Mobile Sources 

Our general approach for assembling data was to use as much existing data from the pre-Base F 

preliminary projections as possible for these inventories, supplement these data with easily 

available stakeholder input, and provide the results for stakeholder review to ensure credibility. 

To develop the “base case” projections, MACTEC originally assembled data to develop two 

2009 and 2018 base case inventories: 1) an inventory that included all “on-the-books” control 

programs and 2) an “on-the-way” inventory that included controls that were likely to be “on-theway”. For the Base F and Base G emission forecasts to the mobile source sector, “on-the-books” 

and “on-the-way” are defined with the same strategies and therefore only a single projection 

scenario was developed for each forecast year. 

To ensure consistency across evaluation years, the 2009 and 2018 base case inventories were 

developed, to the maximum extent practical, using methodologies identical to those employed in 
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developing the 2002 on-road portion of the revised 2002 VISTAS base year inventory. All 

modifications to the 2002 inventory methods were developed in consultation with the Mobile 

Source Special Interest Workgroup (MSSIWG). Generally, modifications were only made to 

properly account for actual changes expected in the intervening period (i.e., between 2002 and 

2009 and between 2002 and 2018), but the underlying inventory development methodology was 

identical, except to the extent requested by VISTAS or the MSSIWG. 

MACTEC developed a preliminary 2018 inventory in early 2004. That inventory was designed 

to 1) be used for modeling sensitivity evaluations and 2) help establish the methods that would 

be used for the final 2018 inventory and the initial 2009 inventory. Since that work took place 

prior to the revision of the 2002 base year inventory data files, MACTEC provided a review of 

the data and methods used to develop on-road mobile source input files for the initial 2002 base 

year inventory prior to developing the preliminary 2018 inventory. Through this review, 

MACTEC determined the following: 

 On-road VMT. Most States provided local data for 2002 (or a neighboring year that was 

converted to 2002 using appropriate VMT growth surrogates such as population). Since 

these data were not applicable to 2018 due to intervening growth, input for 2018 was 

solicited from the MSSIWG. At the same time we researched county-specific growth rate 

data utilized for recent national rulemakings as a backstop approach to State supplied 

VMT projections. 

 Modeling Temperatures. Actual 2002 temperatures were used for the initial 2002 base 

year inventory. 

 Vehicle Registration Mix (age fractions by type of vehicle). A mix of State, local, and 

MOBILE6 default data were used for the 2002 initial base year inventory. Forecast data 

were solicited from the States, with a fallback position that we hold the fractions constant 

at their 2002 values. 

 Vehicle Speed by Roadway Type. For the 2002 initial base year inventory, speeds 

varying by vehicle and road type were used. 

 VMT Mixes (fraction of VMT by vehicle type). A mix of State, local, and quasi 

MOBILE6 default (i.e., MOBILE6 defaults normalized to better reflect local conditions) 

data were used for the 2002 initial base year inventory. Forecast data were solicited from 

the States. 

 Diesel Sales Fractions. As with the VMT mix data, the diesel sales fraction data 

employed for the 2002 initial base year inventory represents a mix of State, local, and 

quasi MOBILE6 default data. The issues related to updating these data to 2018 are also 
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similar, but are complicated by the fact that MOBILE6 treats diesel sales fraction on a 

model year, rather than age specific basis. Therefore, diesel sales fractions generally 

cannot be held constant across time. Once again, we solicited any local projections, with 

a fallback position that we would keep the data for 2002 and earlier model years constant 

for the forecast inventory, supplemented with MOBILE6 default data for 2003 and newer 

model years. 

 State/Local Fuel Standards. For the 2002 initial base year inventory, these data were 

based on appropriate local requirements and updated data for 2018 was only required if 

changes were expected between 2002 and 2018. There are some national changes in 

required fuel quality for both on-road and non-road fuels that are expected to occur 

between 2002 and 2018 and these would be reflected in the 2018 inventory in the absence 

of more stringent local fuel controls. Expected changes in local fuel control programs 

were solicited. 

 Vehicle Standards. The 2002 initial base year inventory assumed NLEV applicability. 

This was altered to reflect Tier 2 for 2018, unless a State indicated a specific plan to 

adopt the California LEV II program. If so, we made the required changes to implement 

those plans for the preliminary 2018 inventory. 

 Other Local Controls. This includes vehicle emissions inspection (i.e., I/M) programs, 

Stage II vapor recovery programs, anti tampering programs, etc. By nature, the 

assumptions used for the 2002 initial base year inventory vary across the VISTAS region, 

but our presumption is that these data accurately reflected each State’s situation as it 

existed in 2002. If a State had no plans to change program requirements between 2002 

and 2018, we proposed to maintain the 2002 program descriptions without change. 

However, if a State planned changes, we requested information on those plans. In the 

final implementation of the Base F and earlier inventories, Stage II controls were 

exercised in the area source component of the inventory, since the units used to develop 

Stage II refueling estimates are different between MOBILE6 and the NONROAD 

models. However, in the Base G inventories, Stage II refueling was moved to the on-road 

and non-road sectors. 

Once the preliminary 2018 (pre-Base F) base case projection inventory data were compiled, 

MACTEC applied the data and methods selected and proceeded to develop the preliminary (prebase F) base case 2018 projection inventories. The resulting inventories were provided to the 

MSSIWG in a user-friendly format for review. After stakeholder review and comment, the final 

preliminary 2018 base case inventories and input files were provided to VISTAS in formats 

identified by the VISTAS Technical Advisor (in this case, MOBILE input files and VMT, 

NONROAD input files and annual inventory files for NONROAD in NIF 3.0 format). Annual 
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inventory files for MOBILE were not developed as part of this work, only input files and VMT 

forecasts. MOBILE emissions were calculated by VISTAS air quality modeling contractor using 

the provided files. 

2.3.1 Development of on-road mobile source input files 

As indicated above, MACTEC prepared a preliminary version of the 2018 base case mobile 

inventory input data files. These files were then updated to provide a final set of 2018 base case 

inventory input data files as well as a set of input files for 2009. The information below describes 

the updates performed on the preliminary 2018 files and the development of the 2009 input 

data files for Base F emission estimation. 

Our default approach to preparing the revised 2018 and initial 2009 projection inventories for onroad mobile sources was to estimate the emissions by using either: 

1. the revised 2002 data provided by each State coupled with the projection methods 

employed for the preliminary 2018 inventory, or 

2. the same data and methods used to generate the preliminary 2018 inventory. 

We also investigated whether or not there was more recent VMT forecasting data available (e.g., 

from the CAIR and if appropriate revised the default VMT growth rates accordingly. This did 

not affect any State that provided local VMT forecasting data, but would alter the VMT 

estimates used for other areas. 

Since no preliminary 2009 inventory was developed there did not exist an option (2) above for 

2009. As a consequence, MACTEC crafted the 2009 initial inventory for on-road mobile sources 

using methods identical to those employed for the 2018 preliminary inventories coupled with any 

changes/revisions provided by the States during the review of the revised 2002 base year and the 

2018 preliminary inventories. Therefore, as was the case for 2018, we obtained from the States 

any input data revisions, methodological revisions, and local control program specifications (to 

the extent that they differed from 2002/2018). 

2.3.1.1 Preparation of revised 2018 input data files 

Preparation of the revised 2018 inventories required the following updates: 

1. The evaluation year was updated to 2018 in all files. 

2. The diesel fuel sulfur content was revised from 500 ppm to 11 ppm, consistent with 

EPA data for 2018 in all files. 

3. Since the input data is model year, rather than age, specific for diesel sales fractions 

(with data for the newest 25 model years required), we updated all files that included 
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diesel sales fractions. In the revised 2002 base year files, the data included applied to 

model years 1978-2002. For 2018, the data included would reflect model years 1994-

2018. To forecast the 2002 data, MACTEC took the data for 1994-2002 from the 

2002 files and added data for 2003-2018. To estimate the data for these years, we 

employed the assumption employed by "default" in MOBILE6 -- namely that diesel 

sales fractions for 1996 and later are constant. Therefore, we set the diesel sales 

fractions for 2003-2018 at the same value as 2002. 

4. VMT mix fractions must be updated to reflect expected changes in sales patterns 

between 2002 and 2018. If explicit VMT mix fractions are not provided, these 

changes are handled internally by MOBILE6 or externally through absolute VMT 

distributions. However, files that include explicit VMT mix fractions override the 

default MOBILE6 update and may or may not be consistent with external VMT 

distributions. MACTEC updated the VMT mix in such files as follows: 

First, we calculated the VMT fractions for LDV, LDT1, LDT2, HDV, and MC 

from the external VMT files for 2018. This calculation was performed in 

accordance with section 5.3.2 of the MOBILE6 Users Guide which indicates: 

LDV = LDGV + LDDV 

LDT1 = LDGT1 + LDDT 

LDT2 = LDGT2 

HDV = HDGV + HDDV 

MC = MC 

The resulting five VMT fractions were then split into the 16 fractions required by 

MOBILE6 using the distributions for 2018 provided in Appendix D of the 

MOBILE6 Users Guide. This approach ensures that explicit input file VMT 

fractions are consistent with the absolute VMT distributions prepared by 

MACTEC. These changes were made to all files that included VMT mixes. 

5. All other input data were retained at 2002 values, except as otherwise instructed by 

the States. This includes all control program descriptions (I/M, Anti-Tampering 

Program [ATP], Stage II, etc.), all other fuel qualities (RVP, oxy content, etc.), all 

other vehicle descriptive data (registrations age distributions, etc.), and all scenario 

descriptive data. The State-specific updates performed are described below. 

Kentucky:

MACTEC revised the 2018 input files for the Louisville, Kentucky area (Louisville Air Pollution 

Control District [APCD]) based on comments received relative to several components of 
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MOBILE input data. Based on these comments, the input files for Jefferson County, Kentucky 

were updated accordingly as follows: 

a) I/M and tampering program definitions were removed since the program was 

discontinued at the end of 2003. 

b) The "Speed VMT", "Facility VMT" and "Registration Age Distribution" file pointers 

were updated to reflect revised 2002 files provided by the Louisville APCD. 

c) The "VMT Mix" data, which was previously based on the default approach of 

"growing" 2002 data, was replaced by 2018-specific data provided by the Louisville 

APCD. 

North Carolina:

North Carolina provided a wide range of revised input data, including complete MOBILE6 input 

files for July modeling. MACTEC did not use the provided input files directly as they did not 

match the 2002 NC input files for critical elements such as temperature distributions and 

gasoline RVP (while they were close, they were slightly different). To maintain continuity 

between 2002 and 2018 modeling, MACTEC instead elected to revise the 2002 input files to 

reflect all control program and vehicle-related changes implied by the new 2018 files, while 

retaining the basic temperature and gasoline RVP assumptions at their 2002 values. Under this 

approach, the following changes were made: 

a) NC provided a county cross reference file specific to 2018 that differed from that 

used for 2002. We removed files that were referenced in the 2002 input data and 

replaced those files with those referenced in the 2018 data. In addition, since NC only 

provided 2018 input files for July, we estimated the basic data for these new files for 

the other months by cross referencing the target files for 2002 by county against the 

target files for 2018 by county. 

b) We then revised the 2002 version of each input file to reflect the 2018 "header" data 

included in the NC-provided 2018 files. These data are exclusively limited to I/M and 

ATP program descriptions, so that the 2002 I/M and ATP data were replaced with 

2018 I/M and ATP data. 

c) We retained the registration age fractions at their 2002 "values" (external file 

pointers) as per NC instructions. 

d) We retained all scenario-specific data (i.e., temperatures, RVP, etc.) at 2002 values, 

which (as indicated above), were slightly different in most cases from data included 

in the 2018 files provided by NC. We believe these differences were due to small 

deviations between the data assembled to support VISTAS 2002 and the process used 

to generate the 2018 files provided by NC, and that revising the VISTAS 2002 data to 
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reflect these variations was not appropriate given the resulting inconsistencies that 

would be reflected between VISTAS 2002 and VISTAS 2018. 

e) NC also provided non-I/M versions of the 2018 input files that would generally be 

used to model the non-I/M portion of VMT. While these files were retained they were 

not used for the 2018 input data preparation. 

Finally, NC also provided a speed profile file and a speed profile cross reference file for 2018. 

We did not use these in our updates as they have no bearing on the MOBILE6 input files, but 

they were maintained in case they needed to be included in SMOKE control files for a future 

year control strategy scenario. 

Virginia:

In accordance with instructions from VA, the input files that referenced an external I/M 

descriptive program file (VAIM02.IM) were revised to reference an alternative external file 

(VAIM05.IM). This change was to make the I/M program more relevant to the year 2018. 

One additional important difference was made with respect to the revised 2018 and initial 2009 

on-road mobile source input data files for all States. MACTEC developed updated SMOKE 

ready input files rather than MOBILE6 files so that the input data could be used directly by the 

VISTAS modeling contractor to estimate on-road mobile source emissions during modeling runs. 

2.3.1.2 Preparation of initial 2009 input data files 

The methodology used to develop the 2009 on-road input files was based on forecasting the 

previously developed revised 2002 base year input files and is identical to that previously 

described for the revised 2018 methodology except as follows: 

1. The evaluation year was updated to 2009. 

2. Diesel fuel sulfur content was revised from 500 ppm to 29 ppm. The 29 ppm value 

was derived from an EPA report entitled "Summary and Analysis of the Highway 

Diesel Fuel 2003 Pre-compliance Reports" (EPA420-R-03-013, October 2003), 

which includes the Agency's estimates for the year-to-year fuel volumes associated 

with the transition from 500 ppm to 15 ppm diesel fuel. According to Table 2 of the 

report, there will be 2,922,284 barrels per day of 15 ppm diesel distributed in 2009 

along with 110,488 barrels per day of 500 ppm diesel. Treating the 15 ppm diesel as 

11 ppm on average (consistent with EPA assumptions and assumptions employed for 

the 2018 input files) and sales weighting the two sulfur content fuels results in an 

average 2009 diesel fuel sulfur content estimate of 29 ppm. 
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3. Diesel sales fractions were updated identically to 2018 except that the diesel sales 

fractions for 2003-2009 were set at the same value as those for 2002 (rather than 

2003-2018). 

4. VMT mix fractions were updated to 2009 using an identical method to that described 

for 2018. 

5. All other input data were retained at 2002 values, except as otherwise instructed by 

individual States (see below). This includes all control program descriptions (I/M, 

ATP, Stage II, etc.), all other fuel qualities (RVP, oxy content, etc.), all other vehicle 

descriptive data (registration age distributions, etc.), and all scenario descriptive data. 

In addition to the updates described above that were applied to all VISTAS-region inputs, the 

following additional State-specific updates were performed: 

KY – Identical changes to those made for 2018 (but specific to 2009) were made for the 

2009 input files. 

NC – Identical changes to those made for 2018 (but specific to 2009) were made for the 2009 

input files. 

VA – Identical changes to those made for 2018 were made for 2009. 

2.3.2 VMT Data 

The basic methodology used to generate the 2009 and 2018 VMT for use in estimating on-road 

mobile source emissions was as follows: 

1. All estimates start from the final VMT estimates used for the 2002 revised base year 

inventory. 

2. Initial 2009 and 2018 VMT estimates were based on linear growth rates for each 

State, county, and vehicle type as derived from the VMT data assembled by the U.S. 

EPA for their most recent HDD (heavy duty diesel) rulemaking. The methodology 

used to derive the growth factors is identical to that employed for the preliminary 

2018 VMT estimates (which is described in the next section). 

3. For States that provided no independent forecast data, the estimates derived in step 2 

are also the final estimates. These States are: Alabama, Florida, Georgia, Kentucky, 

Mississippi, and West Virginia. For States that provided forecast data, the provided 

data were used to either replace or augment the forecast data based on the HDD rule. 

These States, and the specific approaches employed, are detailed following the 

growth method description. 

The steps involved in performing the growth estimates for VMT were as follows: 
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1. Linear growth estimates were used (although MACTEC investigated the potential use 

of nonlinear factors and presented that information to the MSSIWG, the decision was 

made to use linear growth factors instead of nonlinear). 

2. Estimates were developed at the vehicle class (i.e., LDGV, LDGT1, LDGT2, etc.) 

level of detail since the base year 2002 estimates were presented at that level of 

resolution. In effect, the county and vehicle class specific growth factors were applied 

to the 2002 VMT estimates for each vehicle and road class. 

3. Overall county-specific VMT estimates for each year (developed by summing the 

vehicle and road class specific forecasts) were then compared to overall countyspecific growth. Since overall county growth is a more appropriate controlling factor 

as it includes the combined impacts of all vehicle classes, the initial year-specific 

vehicle and road class VMT forecasts were normalized so that they matched the 

overall county VMT growth. Mathematically, this process is as follows: 

(Est_rv_f) = (Est_rv_i) * (C_20XX / Sum(Est_rv_i)) 

where: 

Est_rv_f = the final road/vehicle class-specific estimates, 

Est_rv_i = the initial road/vehicle class-specific estimates, and 

C_20XX = the county-specific growth target for year 20XX. 

Table 2.3-1 presents a basic summary of the forecasts for the preliminary 2018 inventory for 

illustrative purposes: 

Table 2.3-1 2002 versus 2018 VMT (million miles per year) 

State 2002 2018 Growth Factor 

Alabama 55,723 72,966 1.309 

Florida 178,681 258,191 1.445 

Georgia 106,785 148,269 1.388 

Kentucky 51,020 66,300 1.299 

Mississippi 36,278 46,996 1.295 

North Carolina 80,166 110,365 1.377 

South Carolina 47,074 63,880 1.357 

Tennessee 68,316 91,647 1.342 

Virginia 76,566 102,971 1.345 

West Virginia 19,544 24,891 1.274 
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The following States provided some types of forecast data for VMT. The information presented 

below indicates how those data were processed by MACTEC for use in the VISTAS projection 

inventories. 

Kentucky: 

Revised 2009 and 2018 VMT mix data were provided by the Louisville APCD. Therefore, the 

distribution of Jefferson County VMT by vehicle type within the KY VMT file was revised to 

reflect the provided mix. This did not affect the total forecasted VMT for either Jefferson County 

or the State, but does alter the fraction of that VMT accumulated by each of the eight vehicle 

types reflected in the VMT file. The following procedure was employed to make the 

VMT estimates consistent with the provided 2009/2018 VMT mix: 

a) The 16 MOBILE6 VMT mix fractions were aggregated into the following five vehicle 

types: LDV, LDT1, LDT2, HDV, and MC. 

b) The 8 VMT mileage classes were aggregated into the same five vehicle types (across all 

roadway types) and converted to fractions by normalizing against the total Jefferson 

County VMT. 

c) The ratio of the "desired" VMT fraction (i.e., that provided in the Louisville APCD VMT 

mix) to the "forecasted" VMT fraction (i.e., that calculated on the basis of the forecasted 

VMT data) was calculated for each of the five vehicle classes. 

d) All forecasted VMT data for Jefferson County were multiplied by the applicable ratio 

from step c as follows: 

new LDGV = old LDGV * LDV ratio 

new LDGT1 = old LDGT1 * LDT1 ratio 

new LDGT2 = old LDGT2 * LDT2 ratio 

new HDGV = old HDGV * HDV ratio 

new LDDV = old LDDV * LDV ratio 

new LDDT = old LDDT * LDT1 ratio 

new HDDV = old HDDV * HDV ratio 

new MC = old MC * MC ratio 

The total forecasted VMT for Jefferson County was then checked to ensure that it was 

unchanged. 

North Carolina: 

North Carolina provided both VMT and VMT mix data by county and roadway type for 2018. 

Therefore, these data replaced the data developed for North Carolina using HDD rule growth 
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rates in their entirety. Similar data were submitted for 2009. Table 2.3-2 presents the resulting 

VMT estimates which differ from the "default" HDD rule estimates as follows: 

Table 2.3-2 VMT and HDD Rule Estimates for North Carolina (million miles per year) 

North Carolina 

2002 106,795 

State Data HDD Data 

2009 123,396 124,626 

2018 129,552 146,989 

As indicated, there are substantial reductions in the State-provided forecast data relative to that 

derived from the HDD rule. The growth rates for both 2009 and 2018 are only about half that 

implied by the HDD data (1.15 versus 1.17 for 2009 and 1.21 versus 1.38 for 2018). The 

resulting growth rates are the lowest in the VISTAS region. 

NC did not provide VMT mix data for 2009. Therefore, the VMT mix fractions estimated using 

the "default" HDD rule growth rates were applied to the State-provided VMT estimates to 

generate vehicle-specific VMT. Essentially, the default HDD methodology produces VMT 

estimates at the county-road type-vehicle type level of detail, and these data can be converted 

into VMT fractions at that same level of detail. Note that these are not HDD VMT fractions, but 

VMT fractions developed from 2002 NC data using HDD vehicle-specific growth rates. In 

effect, they are 2002 NC VMT fractions "grown" to 2009. 

The default VMT mix fraction was applied to the State-provided VMT data at the county and 

road type level of detail to generate VMT data at the county-road type-vehicle type level of 

detail. The one exception was for county 063, road 110, for which no VMT data were included in 

the HDD rule. For this single county/road combination, State-aggregate VMT mix fractions 

(using the HDD growth methodology) were applied to the county/road VMT data. The difference 

between road 110 VMT fractions across all NC counties is minimal, so there is no effective 

difference in utilizing this more aggregate approach vis-à-vis the more resolved county/road 

approach. 

South Carolina: 

South Carolina provided county and roadway type-specific VMT data for several future years. 

Data for 2018 was included and was used directly. Data for 2009 was not included, but was 

linearly interpolated from data provided for 2007 and 2010. The data were disaggregated into 

vehicle type-specific VMT using the VMT mixes developed for South Carolina using the HDD 

rule VMT growth rates. Table 2.3-3 presents the resulting VMT estimates which differ from the 

"default" HDD rule estimates as follows: 
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Table 2.3-3 VMT and HDD Rule Estimates for South Carolina (million miles per year) 

South Carolina 

2002 47,074 

State Data HDD Data 

2009 55,147 54,543 

2018 65,133 63,880 

Tennessee: 

In general, Tennessee estimates are based on the HDD rule growth rate as described in step two. 

However, Knox County provided independent VMT estimates for 2018 and these were used in 

place of the HDD rule-derived estimates. The Knox County estimates were total county VMT 

data only, so these were disaggregated into roadway and vehicle-type VMT using the 

distributions developed for Knox County in step two using the HDD rule VMT growth rates. No 

data for Knox County were provided for 2009, so the estimates derived using the HDD rule 

growth factors were adjusted by the ratio of "Knox County provided 2018 VMT" to "Knox 

County HDD Rule-derived 2018 VMT." Table 2.3-4 presents the resulting VMT estimates which 

differ from the "default" HDD rule estimates as follows: 

Table 2.3-4 VMT and HDD Rule Estimates for Tennessee (million miles per year) 

Tennessee 

2002 68,316 

State Data HDD Data 

2009 78,615 78,813 

2018 91,417 91,647 

Virginia: 

Virginia provided county and roadway type-specific annual VMT growth rates and these data 

were applied to Virginia -provided VMT data for 2002 to estimate VMT in both 2009 and 2018. 

Virginia provided VMT mix data for 2002, but not 2009 or 2018. Therefore, the estimated VMT 

data for both 2009 and 2018 were disaggregated into vehicle type-specific VMT using the VMT 

mixes developed for VA using the HDD rule VMT growth rates. Table 2.3-5 presents the 

resulting VMT estimates which differ from the "default" HDD rule estimates as follows: 
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Table 2.3-5 VMT and HDD Rule Estimates for Virginia (million miles per year) 

Virginia 

2002 77,472 

State Data HDD Data 

2009 88,419 89,196 

2018 104,944 104,164 

2.3.3 Base G Revisions 

For the development of the VISTAS 2009 and 2018 Base G inventories and input files, VISTAS 

states reviewed the Base F inputs, and provided corrections, updates and supplemental data as 

noted below. 

For all states modeled, the Base G updates include: 

 Adding Stage II refueling emissions calculations to the SMOKE processing. 

 Revised the HDD compliance. (REBUILD EFFECTS = .1) 

 Revised Diesel sulfur values in 2009 to 43 ppm and 2018 to 11 ppm 

In addition to the global changes, individual VISTAS states made the following updates: 

KY – updated VMT and M6 input values for selected counties 

NC – revised VMT estimates, speeds and vehicle distributions and updated registration 

distributions for Mobile 6. 

TN - revised VMT and vehicle registration distributions for selected counties. 

WV – revised VMT input data 

AL, FL, and GA and VA did not provide updates for 2009/2018 Base G, and the Base F inputs 

were used for these States. 

2.3.4 Development of non-road emission estimates 

The sections that follow describe the projection process used to develop 2009 and 2018 non-road 

projection estimates, as revised through the spring of 2006, for sources found in the NONROAD 

model and those sources estimated outside of the model (locomotives, airplanes and commercial 

marine vessels). 

2.3.4.1 NONROAD model sources 

NONROAD model input files were prepared in both the fall of 2004 (Base F) and the spring of 

2006 (Base G) based on the corresponding 2002 base year inventory input files available at the 
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time the forecasts were developed, with appropriate updates for the projection years. Generally, 

this means that the Base F 2002 base year input files (as updated through the fall of 2004) were 

used as the basis for Base F projection year input file development and Base G 2002 base year 

input files as updated through the spring of 2006 were used as the basis for Base G projection 

year input file development. Thus, all base year revisions are inherently incorporated into the 

associated projection year revisions. Other specific updates for the projection years for 

NONROAD model sources consist of: 

1. Revise the emission inventory year in the model (as well as various output file 

naming commands) to be reflective of the projection year. 

2. Revise the fuel sulfur content for gasoline and diesel powered equipment. 

3. Implement a limited number of local control program charges (national control 

program changes are handled internally within the NONROAD model, so explicit 

input file changes are not required). 

All equipment population growth and fleet turnover impacts are also handled internally within 

the NONROAD model, so that explicit changes input file changes are not required. 

Base F Input File Changes: 

To correctly account for diesel fuel sulfur content differences between the base and projection 

years, two sets of input and output files were prepared for each forecast year, one set for landbased equipment and one set for marine equipment. This two-step projection process was 

required for Base F, because diesel fuel sulfur contents varied between land-based and 

marine-based non-road equipment and the Draft NONROAD2004 used for Base F allowed only 

a single diesel fuel sulfur input. Thus, the model was executed separately for land-based and 

marine-based equipment for Base F, and the associated outputs subsequently combined. The 

specific diesel fuel sulfur contents modeled were as follows: 

Diesel S (ppm) 2002 2009 2018 

 Land-Based 2500 348 11 

 Marine-Based 2500 408 56 

As indicated, the Draft NONROAD2004 model was run with both sets of input files and the 

output file results were then combined to produce a single NONROAD output set. 

To correctly account for the national reduction in gasoline sulfur content (a national control not 

explicitly handled by the NONROAD model), all NONROAD input files for both 2009 and 2018 

were revised to reflect a gasoline fuel sulfur content of 30 ppmW. 
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Base G Input File Changes: 

With the release of Final NONROAD2005 that was used for the Base G projection year 

inventory development, the NONROAD model is capable of handling separate diesel fuel sulfur 

inputs for land-based and marine-based non-road equipment in a single model execution. 

Therefore, the two step modeling process described above for Base F updates was no longer 

required. Instead, the differential diesel fuel sulfur values are assembled into a single 

NONROAD input file as follows: 

Diesel S (ppm) 2002 2009 2018 

 Land-Based 2500 348 11 

 Marine-Based 2638 408 56 

Additionally, revised gasoline vapor pressure data were provided by Georgia regulators for 20 

counties5 where reduced volatility requirements were established in 2003. Since this requirement 

began after the 2002 base year, the vapor pressure values in the base year input files for these 

counties are not correct for either the 2009 or 2018 forecast years. Therefore, to correctly 

forecast emissions in these counties, the forecast year gasoline vapor pressure inputs were 

revised to: 

Gasoline RVP (psi) 2002 2009 2018 

 Spring 9.87 9.2 9.2 

 Summer 9.0 7.0 7.0 

 Fall 9.87 9.2 9.2 

 Winter 12.5 12.5 12.5 

The summer vapor pressure was simply set equal to the 2003 control value, while the spring and 

fall vapor pressures were adjusted to reflect a single month of the reduced volatility limit. The 

winter volatility was assumed to be unaffected by the summertime control requirement. 

2.3.4.1.1 Differences between 2009/2018 

Other than diesel fuel sulfur content and the year of the projections, there are no differences in 

the methodology used to estimate emissions from NONROAD model sources. As indicated 

above, however the Base F 2009/2018 projections were developed using Draft NONROAD2004, 

while the Base G 2009/2018 projections were made using Final NONROAD2005. 

 

5

 The specific counties are: Banks, Chattooga, Clarke, Floyd, Gordon, Heard, Jasper, Jones, Lamar, Lumpkin, 

Madison, Meriwether, Monroe, Morgan, Oconee, Pike, Polk, Putnam, Troup, and Upson. 
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2.3.4.2 Non-NONROAD model sources 

Using the 2002 base year emissions inventory for aircraft, locomotives, and commercial marine 

vessels (CMV) prepared as described earlier in this document, corresponding emission 

projections for 2009 and 2018 were developed in both the fall of 2004 (Base F) and the spring of 

2006 (Base G). This section describes the procedures employed in developing those inventories. 

The information presented is intended to build off of that presented in the section describing the 

2002 Base F base year inventory. It should be recognized that for both the Base F and Base G 

inventories, the base year inventory used to develop the emission forecasts was the latest 

available at the time of forecast development. Generally, this means that the 2002 base year 

inventory as updated through the fall of 2004 was used as the basis for the Base F projection year 

inventory development, and the Base F 2002 base year inventory was used as the basis for Base 

G projection year inventory development. Thus, all base year revisions (as described earlier in 

this document) are inherently incorporated into the associated projection year revisions. 

Base F Revisions: 

Table 2.3-6 shows the 2002 base year emissions for each State in the VISTAS region for aircraft, 

locomotives and CMV (as they existed prior to Base F development). 
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Table 2.3-6 Pre-Base F 2002 Aircraft, Locomotive, and Non-Recreational 

Marine Emissions 

(annual tons, as of the fall of 2004)

Source State CO NOx PM10 PM2.5 SO2 VOC 

AL 3,787 175 226 87 17 196 

FL 25,431 8,891 2,424 2,375 800 3,658 

GA 6,620 5,372 1,475 1,446 451 443 

KY 2,666 657 179 175 63 263 

MS 1,593 140 44 43 13 96 

NC 6,088 1,548 419 411 148 613 

SC 6,505 515 409 401 88 863 

TN 7,251 2,766 734 719 235 943 

VA 9,763 2,756 1,137 1,115 786 2,529 

WV 1,178 78 25 24 8 66 

Aircraft 

(2275) 

Total 70,882 22,899 7,072 6,797 2,607 9,670 

AL 1,196 9,218 917 844 3,337 737 

FL 5,888 44,817 1,936 1,781 6,683 1,409 

GA 1,038 7,875 334 307 1,173 246 

KY 6,607 50,267 2,246 2,066 9,608 1,569 

MS 5,688 43,233 1,903 1,751 7,719 1,351 

NC 599 4,547 193 178 690 142 

SC 1,067 8,100 343 316 1,205 253 

TN 3,624 27,555 1,217 1,120 4,974 860 

VA 972 2,775 334 307 359 483 

WV 1,528 11,586 487 448 525 362 

Commercial 

Marine 

(2280) 

Total 28,207 209,972 9,911 9,118 36,275 7,413 

Military Marine VA 110 313 25 23 27 48 

(2283) Total 110 313 25 23 27 48 

AL 3,490 26,339 592 533 1,446 1,354 

FL 1,006 9,969 247 222 605 404 

GA 2,654 26,733 664 598 1,622 1,059 

KY 2,166 21,811 542 488 1,321 867 

MS 2,302 23,267 578 520 1,429 899 

NC 1,638 16,502 410 369 1,001 654 

SC 1,160 11,690 291 261 710 462 

TN 2,626 25,627 633 570 1,439 1,041 

VA 1,186 11,882 1,529 1,375 3,641 492 

WV 1,311 13,224 329 296 808 517 

Locomotives 

(2285) 

Total 19,540 187,044 5,815 5,232 14,022 7,750 

Grand Total 118,739 420,228 22,823 21,170 52,931 24,881 
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Although some of the data utilized was updated, the methodology used to develop the Base F 

2009 and 2018 emissions forecasts for aircraft, locomotives, and CMV is identical to that used 

earlier to develop preliminary 2018 Base 1 (“On the Books”) and 2018 Base 2 (“On the Way”) 

inventories. Briefly, the methodology relies on growth and control factors developed from 

inventories used in support of recent EPA rulemakings, and consists of the following steps: 

(a) Begin with the 2002 base year emission estimates for aircraft, locomotive, and CMV as 

described above (at the State-county-SCC-pollutant level of detail). 

(b) Detailed inventory data (both before and after controls) for these same emission sources 

for 1996, 2010, 2015, and 2020 were obtained from the EPA's Clean Air Interstate Rule 

(CAIR) Technical Support Document (which can be found at 

http://www.epa.gov/cair/pdfs/finaltech01.pdf). Using these data, combined growth and 

control factors for the period 2002-2009 and 2002-2018 were estimated using straight 

line interpolation between 1996 and 2010 (for 2009) and 2015 and 2020 (for 2018). This 

is done at the State-county-SCC-pollutant level of detail. 

(c) The EPA growth and control data are matched against the 2002 VISTAS base year data 

using State-county-SCC-pollutant as the match key. Ideally, there would be a one-to-one 

match and the process would end at this point. Unfortunately, actual match results were 

not always ideal, so additional matching criteria were required. For subsequent reference, 

this initial (highest resolution) matching criterion is denoted as the “CAIR-Primary” 

criterion. 

(d) A second matching criterion is applied that utilizes a similar, but higher-level SCC (lower 

resolution) matching approach. For example, SCC 2275020000 (commercial aircraft) in 

the 2002 base year inventory data would be matched with SCC 2275000000 (all aircraft) 

in the CAIR data. This criterion is applied to records in the 2002 base year emissions file 

that are not matched using the “CAIR-Primary” criterion, and is also performed at the 

State-county-SCC-pollutant level of detail. For subsequent reference, this is denoted as 

the “CAIR-Secondary” criterion. At the end of this process, a number of unmatched 

records remained, so a third level matching criterion was required. 

(e) In the third matching step, the most frequently used SCC in the EPA CAIR files for each 

of the aircraft, locomotive, and commercial marine sectors was averaged at the State level 

to produce a “default” State and pollutant-specific growth and control factor for the 

sector. The resulting factor is used as a “default” growth factor for all unmatched 

county-SCC-pollutant level data in each State. In effect, State-specific growth data are 

applied to county level data for which an explicit match between the VISTAS 2002 base 

year data and EPA CAIR data could not be developed. The default growth and control 
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SCCs are 2275020000 (commercial aircraft) for the aircraft sector, 2280002000 

(commercial marine diesel total) for the CMV sector, and 2285002000 (railroad 

equipment diesel total) for the locomotive sector. Matches made using this criterion are 

denoted as “CAIR-Tertiary” matches. 

(f) According to EPA documentation, the CAIR baseline emissions include the impacts of 

the (then proposed) Tier 4 (T4) non-road diesel rulemaking, which implements a low 

sulfur fuel requirement that affects both future CMV and locomotive emissions. 

However, the impacts of this rule were originally intended to be excluded from the initial 

VISTAS 2018 forecast, which was to include only “on-the-books” controls. (The T4 rule 

was finalized subsequent to the development of the preliminary 2018 inventory in March 

of 2004.) Given its final status, T4 impacts were moved into the “on the books” inventory 

for non-road equipment. In addition, since there are no other proposed rules affecting the 

non-road sector between 2002 and 2018, there is no difference between the 2018 “on the 

books” and 2018 “on the way” inventories for the sector; so that only a single forecast 

inventory (for each evaluation year) was developed. Nevertheless, since the algorithms 

developed to produce the VISTAS forecasts were developed when there was a distinction 

between the “on the books” and “on the way” inventories, the distinct algorithms used to 

produce the two inventories have been maintained even though the conceptual 

distinctions have been lost. This approach was taken for two reasons. First, it allowed the 

previously developed algorithms to be utilized without change. Second, it allowed for 

separate treatment of the T4 emissions impact which was important as those impacts 

changed between the proposed and final T4 rules. Thus, previous EPA inventories that 

include the proposed T4 impacts would not be accurate. Therefore, the procedural 

discussion continues to reflect the distinctions between non-T4 and T4 emissions, as 

these distinctions continue to be intrinsically important to the forecasting process. 

Therefore, a second set of EPA CAIR files that excluded the Tier 4 diesel impacts was 

obtained and the same matching exercise described above in steps (b) through (e) was 

performed using these “No T4” files. It is important to note that the matching exercise 

described in steps (b) through (e) cannot simply be replaced because the “No T4” files 

obtained from the EPA include only those SCCs specifically affected by the T4 rule (i.e., 

diesel CMV and locomotives). So in effect, the matching exercise was augmented (rather 

than replaced) with an additional three criteria analogous to those described in steps (c) 

through (e), and these are denoted as the “No T4-Primary,” “No T4-Secondary,” and “No 

T4-Tertiary” criteria. Because they exclude the impacts of the proposed T4 rule, matches 

using the “No T4” criteria supersede matches made using the basic CAIR criteria (as 

described in steps (c) through (e) above). 
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(g) The CAIR matching criteria were overridden for any record for which States provided 

local growth data. Only North Carolina provided these forecasts, as that State has 

provided specific growth factors for airport emissions in four counties. Because the 

provided data were based on forecasted changes in landings and takeoffs at major North 

Carolina airports, the factors were applied only to commercial (SCC 2275020000) and air 

taxi (SCC 2275060000) emissions. Emissions forecasts for military and general aviation 

aircraft operations, as well as all aircraft operations in counties other than the four 

identified in the North Carolina growth factor submission, continued to utilize the growth 

factors developed according to steps (b) through (f) above. Table 2.3-7 presents the 

locally generated growth factors applied in North Carolina. 

Table 2.3-7 Locally Generated Growth Factors for North Carolina 

FIP 2009 Factor 2018 Factor 

37067 0.71 0.84 

37081 0.97 0.89 

37119 1.15 1.01 

37183 0.88 0.81 

Note: 

Growth factor = Year Emissions/2002 Emissions. 

Under CAIR approach, 2009 = 1.16 to 1.17 for all 4 counties. 

Under CAIR approach, 2018 = 1.36 to 1.37 for all 4 counties. 

(h) Using this approach, each State-county-SCC-pollutant was assigned a combined growth 

and control factor using the EPA CAIR forecast or locally provided data. The 22,838 data 

records for aircraft, locomotives, and CMV in the 2002 revised base year emissions file 

were assigned growth factors in accordance with the following breakdown: 

 48 records matched State-provided growth factors, 

 4,179 records matched using the CAIR-Primary criterion, 

 240 records matched using the CAIR-Secondary criterion, 

 7,463 records matched using the CAIR-Tertiary criterion, 

 720 records matched using the No T4-Primary criterion, 

 3,858 records matched using the No T4-Secondary criterion, and 

 6,330 records matched using the No T4-Tertiary criterion. 

(i) Finally, the impacts of the T4 rule as adopted were applied to the grown “non T4” 

emission estimates. The actual T4 emission standards do not affect aircraft, locomotive, 

or CMV directly, but associated diesel fuel sulfur requirements do affect locomotives and 

CMV. Lower fuel sulfur content affects both SO2 and PM emissions. Expected fuel sulfur 
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contents were obtained for each evaluation year from the EPA technical support 

document for the final T4 rule (Final Regulatory Analysis: Control of Emissions from 

Non-road Diesel Engines, EPA420-R-04-007, May 2004). According to that document, 

the average diesel fuel sulfur content for locomotives and CMV is expected to be 408 

ppmW in 2009 and 56 ppmW in 2018. These compare to expected non-T4 fuel sulfur 

levels of 2599 ppmW in 2009 and 2336 ppmW in 2018. Table 2.3-8 uses calculated 

emissions estimates for base and T4 control scenarios to estimate emission 

reduction impacts. 

Table 2.3-8 Estimated Emission Reduction Impacts based on T-4 Rule 

2009 2018

CMV SO2 = Non-T4 SO2 × 0.1569 0.0241

Locomotive SO2 = Non-T4 SO2 × 0.1569 0.0241

CMV PM = Non-T4 PM × 0.8962 0.8762

Locomotive PM = Non-T4 PM × 0.8117 0.7734

However, since the diesel fuel sulfur content assumed for the 2002 VISTAS base year 

inventory, upon which both the 2009 and 2018 inventories were based, is 2500 ppmW, a 

small adjustment to the emission reduction multipliers calculated from the T4 rule is 

appropriate since they are measured relative to modestly different sulfur contents (2599 

ppmW for 2009 and 2336 ppmW for 2018). Correcting for these modest differences 

produces the emission reduction impact estimates relative to forecasts based on the 

VISTAS 2002 inventory shown in Table 2.3-9. 

Table 2.3-9 Estimated Emission Reduction Impacts Relative to VISTAS 2002 Base 

Year Values 

2009 2018

CMV SO2 = Non-T4 SO2 × 0.1632 0.0225

Locomotive SO2 = Non-T4 SO2 × 0.1632 0.0225

CMV PM = Non-T4 PM × 0.9004 0.8685

Locomotive PM = Non-T4 PM × 0.8187 0.7610

These factors were applied directly to the non-T4 emission forecasts to produce the final 

VISTAS 2009 and 2018 emissions inventories for aircraft, locomotive, and CMV. 

The only exception is for Palm Beach County, Florida, where CMV emissions are 

reported as “all fuels” rather than separately by residual and diesel fuel components. To 

estimate T4 impacts in Palm Beach County, the ratio of diesel CMV emissions to total 
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CMV emissions in the remainder of Florida was calculated and the T4 impact estimates 

for Palm Beach County were adjusted to reflect that ratio. Table 2.3-10 shows the 

calculated diesel CMV ratios. 

Table 2.3-10 Diesel CMV Adjustment Ratios for Palm Beach County, FL 

GROWTH BASIS SO2 PM

2009 (1996, 2020 Growth Basis) 0.2410 0.7861 

2009 (1996, 2010, 2015, and 2020 Growth Basis) 0.1279 0.7875 

2018 (1996, 2020 Growth Basis) 0.2432 0.7925 

2018 (1996, 2010, 2015, and 2020 Growth Basis) 0.2624 0.7918 

The differences between the growth bases are discussed in detail below. 

Combining these ratios with the T4 impact estimates for diesel engines, as presented 

above, yields the following impact adjustment factors for Palm Beach County: 

Table 2.3-11 Overall Adjustment Factors for Palm Beach County, FL 

GROWTH BASIS

2009 SO2 (19, 20 Growth Basis) 0.7894 [0.1632×0.2410+(1-0.2410)]

2009 SO2 (96, 10, 15, and 20 Growth Basis) 0.8930 [0.1632×0.1279+(1-0.1279)] 

2018 SO2 (96, 20 Growth Basis) 0.7623 [0.0225×0.2432+(1-0.2432)] 

2018 SO2 (96, 10, 15, and 20 Growth Basis) 0.7436 [0.0225×0.2624+(1-0.2624)] 

2009 PM (19, 20 Growth Basis) 0.9217 [0.9004×0.7861+(1-0.7861)] 

2009 PM (96, 10, 15, and 20 Growth Basis) 0.9216 [0.9004×0.7875+(1-0.7875)] 

2018 PM (96, 20 Growth Basis) 0.8958 [0.8685×0.7925+(1-0.7925)] 

2018 PM (96, 10, 15, and 20 Growth Basis) 0.8959 [0.8685×0.7918+(1-0.7918)]

The differences between the growth bases are discussed in detail below.

Utilizing this approach, emission inventory forecasts for both 2009 and 2018 were developed. As 

indicated in step (b) above, basic growth factors were developed using EPA CAIR inventory data 

for 1996, 2010, 2015, and 2020. From these data, equivalent EPA CAIR inventories for 2002 and 

2009 were developed through linear interpolation of the 1996 and 2010 inventories, while an 

equivalent CAIR inventory for 2018 was developed through linear interpolation of the 2015 and 

2020 inventories. Growth factors for 2009 and 2018 were then estimated as the ratios of the 

CAIR 2009 and 2018 inventories to the CAIR 2002 inventory. 

During the development of the preliminary 2018 VISTAS inventory in March 2004, this process 

yielded reasonable results and exhibited no particular systematic concerns. However, when the 

2009 Base F inventory was developed, significant concerns related to SO2 and PM were 

encountered. Essentially, what was revealed by the Base F 2009 forecast was a series of apparent 
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inconsistencies in the CAIR 2010 and 2015 emission inventories (as compared to the 1996 and 

2020 CAIR inventories) that were masked during the construction of the “longer-term” 

2018 inventory. 

The apparent inconsistencies are best illustrated by looking at the actual data extracted from the 

CAIR inventory files. Note that although a limited example is being presented, the same general 

issue applies throughout the CAIR files. For FIP 01001 (Autauga County, Alabama) and SCC 

2285002000 (Diesel Rail), the CAIR inventories indicate SO2 emission estimates as shown in 

Table 2.3-12. 

Table 2.3-12 SO2 Emissions for Diesel Rail in Autauga County, AL from the 

CAIR Projections 

YEAR TONS 

1996: 15.3445 

2010: 2.7271 

2015: 2.8178 

2020: 16.6232 

Clearly, there is a major drop in emissions between 1996 and 2010, followed by a major increase 

in emissions between 2015 and 2020. Several observations regarding these changes are 

important. First, the CAIR data were reported to exclude the T4 rule, so that the drop in 

emissions should be related to something other than simply a change in diesel fuel sulfur content. 

Second, if the T4 rule impacts were “accidentally” included in the estimates, there should be a 

resultant 90 percent drop in diesel sulfur between 2010 and 2015; so such inclusion is unlikely. 

Third, the rate of growth between 2015 and 2020 (43 percent per year compound or 97 percent 

per year linear) is well beyond any reasonable expectations for rail service; and fuel sulfur 

content during this period is constant both with and without T4. In short, there appeared to be no 

rational explanation for the data, yet the same basic relations are observed for thousands of CAIR 

inventory records. 

For the most part, the issue seems to be centered on SO2 and PM records, which are those 

records primarily affected by the T4 rule. But, as noted above, there does not seem to be any 

pattern of consistency that would indicate that either inclusion or exclusion of T4 rule impacts is 

the underlying cause. Moreover, where they occur, the observed growth extremes generally 

affect both SO2 and PM equally, while one would expect PM effects to be buffered if the T4 rule 

was the underlying cause, since changes in diesel fuel sulfur content will only affect a fraction of 

PM (i.e., sulfate), while directly reducing SO2. 
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The data presented in Figure 2.3-1 illustrates what this meant to the VISTAS forecasting process. 

Figure 2.3-1 depicts the same data presented above for Autauga County, Alabama, but 

normalized so that the interpolated 2002 CAIR emissions estimate equals unity. The “raw” CAIR 

data is depicted by the markers labeled A, B, C, and D. Interpolated data for 2002 and 2009, 

based on 1996 and 2010 CAIR data, is depicted by the markers labeled “i” and “ii.” Interpolated 

data for 2018, based on 2015 and 2020 CAIR data is depicted by the marker labeled “iii.” The 

relationship between marker “iii” and marker “i” is exactly the relationship used to construct the 

preliminary (e.g., pre-Base F) 2018 VISTAS inventory (i.e., a linear growth rate equal to 0.7 

percent per year). Thus, it is easy to see that although there is a major “dip and rise” between 

2002 and 2018, it is essentially masked unless data for intervening years are examined. Since no 

intervening year was examined for the preliminary 2018 inventory, the “dip and rise” was not 

discovered. However, upon the development of the 2009 inventory forecast, the issue became 

obvious, as the marker labeled “ii” readily illustrates. In effect, the 2009 inventory reflected very 

low negative “growth rates” for some SCCs and pollutants relative to the 2002 inventory, while 

the 2018 inventory reflected very high and positive growth rates for those same SCCs and 

pollutants. In effect, the path between 2002 and 2018 that previously looked like the dotted line 

connecting markers “i” and “iii,” now looks like the solid line connecting markers “i”, “ii,” and 

“iii.” For reference purposes, this path is hereafter referred to as the 1996, 2010, 2015, and 2020 

growth basis, since all interpolated data is based on CAIR data for those four years. 

Figure 2.3-1 Impacts of the Apparent CAIR Inventory Discrepancy 

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

1990 1995 2000 2005 2010 2015 2020 2025

Year

Emissions

1

iii

ii

i

D

B C

A

3 2

A,B,C,D = EPA CAIR Data.

i,ii,iii = 96-10-15-20 Interpolations.

1,2,3 = 96-20 Interpolations.

All indicated growth is linear.

i to ii = -9.1%/yr ii to iii = 22.9%/yr

i to iii = 0.7%/yr

1 to 2 to 3 = 0.3%/yr
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In light of the apparent discrepancies inherent in the 1996, 2010, 2015, and 2020 growth basis 

data and the inconsistencies its use would impart into the 2009 and 2018 VISTAS inventories, a 

secondary forecasting method was developed. This second method relies on the apparent 

consistency between the 1996 and 2020 non-T4 CAIR inventories, interpolating equivalent 2002, 

2009, and 2018 inventories solely from these two inventories. In effect, the CAIR inventories for 

2010 and 2015 are ignored. In Figure 2.3-1, this secondary approach is depicted by the data 

points that lie along the lines connecting markers A and D. Markers A and D represent the 1996 

and 2020 CAIR inventories, and the markers labeled 1, 2, and 3 represent the interpolated 2002, 

2009, and 2018 CAIR equivalent inventories. The growth rate between 2009 and 2002 is then 

equal to the ratio of the 2009 and 2002 CAIR inventories, while that between 2018 and 2002 is 

equal to the ratio of the 2018 and 2002 CAIR inventories. For the example data, the resulting 

linear growth estimate is 0.3 percent per year. For reference purposes, this path is hereafter 

referred to as the 1996-2020 growth basis, since all interpolated data are based on CAIR data for 

only those two years. 

It is perhaps worth noting that the only elements of Figure 2.3-1 that have any bearing on the 

VISTAS inventories are the growth rates. The absolute CAIR data are of importance only in 

determining those rates, as all VISTAS inventories were developed on the basis of the VISTAS 

2002 base year inventory, not any of the CAIR inventories. So referring to Figure 2.3-1, the two 

growth options are summarized in Table 2.3-13. 

Table 2.3-13 Growth Options based on CAIR Data 

GROWTH BASIS PERCENT PER YEAR 

1996, 2010, 2015, 2020 Growth Basis: -9.1% per year (linear) between 2002 and 2009 

1996-2020 Growth Basis: +0.3% per year (linear) between 2002 and 2009 

1996, 2010, 2015, 2020 Growth Basis: +22.9% per year (linear) between 2009 and 2018 

1996-2020 Growth Basis: +0.3% per year (linear) between 2009 and 2018 

1996, 2010, 2015, 2020 Growth Basis: +0.7% per year (linear) between 2002 and 2018 

1996-2020 Growth Basis: +0.3% per year (linear) between 2002 and 2018 

Of course, these specific rates are applicable only to the example case (i.e., diesel rail SO2 in 

Autauga County, Alabama), but there are thousands of additional CAIR records that are virtually 

identical from a growth viewpoint. 

While forecast inventories for aircraft, locomotives, and CMV were developed for 2009 and 

2018 using both growth methods, it was ultimately decided to utilize the 1996-2020 growth basis 

for Base F since it provided more reasonable growth rates for 2009. Tables 2.3-14 and 2.3-15 

present a summary of each Base F inventory, while Tables 2.3-16 and 2.3-17 present the 

associated change in emissions for each Base F forecast inventory relative to the Base F 2002 

base year VISTAS inventory. The larger reduction in CMV SO2 emissions in 2009 and 2018 
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(relative to 2002) for Virginia and West Virginia is notable relative to the other VISTAS States, 

but this has been checked and is attributable to a high diesel contribution to total CMV SO2 in 

the 2002 inventories for these two States. 

Figures 2.3-2 through 2.3-13 graphically depict the relationships between the various Base F 

inventories and preliminary 2002 and 2018 projections prepared prior to Base F. There are two 

figures for each pollutant, the first of which presents a comparison of total VISTAS regional 

emission estimates for aircraft, locomotives, and CMV, and the second of which presents total 

VISTAS region emission estimates for locomotives only. This two figure approach is intended to 

provide a more robust illustration of the differences between the various inventories, as some of 

the differences are less distinct when viewed through overall aggregate emissions totals. All of 

the figures include the following emissions estimates: 

 The 2002 Base F base year VISTAS emissions inventory (labeled as “2002”), 

 The 2002 pre-Base F base year VISTAS emissions inventory (labeled as “2002 

Prelim”), 

 The Base F 2009 VISTAS emissions inventory developed using growth rates derived 

from 1996 and 2020 EPA CAIR data (labeled as “2009”), 

 The Base F 2018 VISTAS emissions inventory developed using growth rates derived 

from 1996 and 2020 EPA CAIR data (labeled as “2018”), and 

 The pre-Base F 2018 VISTAS emissions inventory estimates as developed using 

growth rates derived from 1996, 2010, 2015, and 2020 EPA CAIR data (labeled as 

“2018 Prelim”). 

All 12 figures generally illustrate a reduction in emissions estimates between the 2002 pre-Base 

F emission estimates published in February 2004 (the initial 2002 VISTAS inventory) and the 

2002 Base F emission estimates. This reduction generally results from emission updates reflected 

in the State 2002 CERR submittals used to develop the Base F 2002 base year inventory, 

although the major differences in aggregate PM emission estimates are driven to a greater extent 

by modifications in the methodology used to estimate aircraft PM in the Base F 2002 base year 

inventory (as documented under the base year inventory section of this report). 
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Table 2.3-14 Base F 2009 Aircraft, Locomotive, and Non-Recreational Marine Emissions 

(annual tons) -- Based on Growth Using 1996 and 2020 EPA Inventories

Source State CO NOx PM10 PM2.5 SO2 VOC 

AL 4,178 202 278 102 19 217 

FL 29,258 10,316 2,812 2,756 928 4,235 

GA 7,635 6,233 1,712 1,678 523 512 

KY 3,075 762 207 203 73 304 

MS 1,765 162 51 50 16 108 

NC 6,551 1,601 436 427 153 644 

SC 7,372 559 446 437 98 975 

TN 8,020 3,096 824 807 268 1,050 

VA 10,994 3,094 1,239 1,214 907 2,892 

WV 1,312 91 28 28 9 74 

Aircraft 

(2275) 

Total 80,159 26,116 8,033 7,704 2,993 11,011 

AL 1,280 8,888 872 802 2,753 768 

FL 6,236 43,198 1,838 1,691 5,864 1,467 

GA 1,097 7,599 317 291 974 256 

KY 7,087 48,039 2,158 1,985 8,350 1,649 

MS 6,074 41,437 1,821 1,676 6,587 1,415 

NC 634 4,386 184 169 584 148 

SC 1,133 7,796 326 300 1,012 264 

TN 3,887 26,333 1,168 1,074 4,512 904 

VA 1,042 2,662 312 286 61 506 

WV 1,638 11,073 455 419 89 381 

Commercial 

Marine 

(2280) 

Total 30,109 201,412 9,450 8,693 30,786 7,759 

Military Marine VA 118 299 23 21 5 50 

(2283) Total 118 299 23 21 5 50 

AL 3,648 23,529 452 406 242 1,279 

FL 1,052 8,905 189 170 101 382 

GA 2,769 24,398 507 456 271 1,003 

KY 2,264 19,597 415 374 221 819 

MS 2,406 20,785 441 397 239 849 

NC 1,712 14,741 313 282 167 618 

SC 1,213 10,443 222 200 119 437 

TN 2,745 23,924 483 435 240 984 

VA 1,236 11,134 1,167 1,050 608 467 

WV 1,369 12,177 251 226 135 489 

Locomotives 

(2285) 

Total 20,412 169,635 4,440 3,995 2,343 7,328 

Grand Total 130,798 397,462 21,946 20,413 36,126 26,148 
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Table 2.3-15 Base F 2018 Aircraft, Locomotive, and Non-Recreational Marine Emissions 

(annual tons) -- Based on Growth Using 1996 and 2020 EPA Inventories

Source State CO NOx PM10 PM2.5 SO2 VOC 

AL 4,681 236 345 122 23 245 

FL 34,178 12,147 3,312 3,246 1,093 4,976 

GA 8,939 7,340 2,016 1,976 616 601 

KY 3,602 898 244 239 86 357 

MS 1,986 190 60 58 18 122 

NC 6,728 1,454 400 392 139 615 

SC 8,487 616 493 484 112 1,119 

TN 9,009 3,519 939 921 309 1,187 

VA 12,578 3,528 1,370 1,342 1,063 3,358 

WV 1,484 106 33 33 10 85 

Aircraft 

(2275) 

Total 91,670 30,035 9,213 8,814 3,468 12,666 

AL 1,388 8,464 880 809 2,715 809 

FL 6,684 41,117 1,853 1,705 6,248 1,543 

GA 1,174 7,246 319 293 976 269 

KY 7,703 45,174 2,199 2,023 8,383 1,752 

MS 6,571 39,129 1,850 1,702 6,556 1,498 

NC 679 4,179 185 170 596 155 

SC 1,217 7,406 329 303 1,027 278 

TN 4,225 24,763 1,190 1,095 4,808 960 

VA 1,133 2,517 314 289 9 537 

WV 1,781 10,412 459 422 13 404 

Commercial 

Marine 

(2280) 

Total 32,554 190,407 9,578 8,811 31,330 8,205 

Military Marine VA 128 282 23 21 1 53 

(2283) Total 128 282 23 21 1 53 

AL 3,850 19,917 381 343 34 1,183 

FL 1,110 7,538 159 143 14 353 

GA 2,917 21,395 427 385 38 932 

KY 2,389 16,751 352 317 31 757 

MS 2,540 17,594 372 335 34 785 

NC 1,807 12,478 264 237 24 571 

SC 1,280 8,840 187 168 17 404 

TN 2,897 21,735 407 367 34 910 

VA 1,300 10,173 983 885 86 436 

WV 1,444 10,831 212 190 19 453 

Locomotives 

(2285) 

Total 21,534 147,252 3,744 3,368 333 6,785 

Grand Total 145,885 367,975 22,557 21,015 35,132 27,709 
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Table 2.3-16 Change in Emissions between 2009 and 2002 Base F Inventories (Based on 

Growth Using 1996 and 2020 EPA Inventories)

Source State CO NOx PM10 PM2.5 SO2 VOC 

AL +10% +15% +23% +18% +16% +11% 

FL +15% +16% +16% +16% +16% +16% 

GA +15% +16% +16% +16% +16% +16% 

KY +15% +16% +16% +16% +16% +16% 

MS +11% +16% +15% +15% +16% +12% 

NC +8% +3% +4% +4% +3% +5% 

SC +13% +9% +9% +9% +12% +13% 

TN +11% +12% +12% +12% +14% +11% 

VA +13% +12% +9% +9% +15% +14% 

WV +11% +16% +15% +15% +16% +12% 

Aircraft 

(2275) 

Total +13% +14% +14% +13% +15% +14% 

AL +7% -4% -5% -5% -18% +4% 

FL +6% -4% -5% -5% -12% +4% 

GA +6% -3% -5% -5% -17% +4% 

KY +7% -4% -4% -4% -13% +5% 

MS +7% -4% -4% -4% -15% +5% 

NC +6% -4% -5% -5% -15% +4% 

SC +6% -4% -5% -5% -16% +4% 

TN +7% -4% -4% -4% -9% +5% 

VA +7% -4% -7% -7% -83% +5% 

WV +7% -4% -7% -7% -83% +5% 

Commercial 

Marine 

(2280) 

Total +7% -4% -5% -5% -15% +5% 

Military Marine VA +7% -4% -7% -7% -83% +5% 

(2283) Total +7% -4% -7% -7% -83% +5% 

AL +5% -11% -24% -24% -83% -6% 

FL +5% -11% -24% -24% -83% -6% 

GA +4% -9% -24% -24% -83% -5% 

KY +5% -10% -23% -23% -83% -6% 

MS +5% -11% -24% -24% -83% -6% 

NC +5% -11% -24% -24% -83% -6% 

SC +5% -11% -24% -24% -83% -6% 

TN +5% -7% -24% -24% -83% -6% 

VA +4% -6% -24% -24% -83% -5% 

WV +4% -8% -24% -24% -83% -5% 

Locomotives 

(2285) 

Total +4% -9% -24% -24% -83% -5% 

Grand Total +10% -5% -4% -4% -32% +5% 
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Table 2.3-17 Change in Emissions between 2018 and 2002 Base F Inventories (Based on 

Growth Using 1996 and 2020 EPA Inventories)

Source State CO NOx PM10 PM2.5 SO2 VOC 

AL +24% +35% +53% +41% +36% +25% 

FL +34% +37% +37% +37% +37% +36% 

GA +35% +37% +37% +37% +37% +36% 

KY +35% +37% +37% +37% +37% +36% 

MS +25% +36% +35% +35% +36% +27% 

NC +10% -6% -5% -5% -6% 0% 

SC +30% +20% +21% +21% +27% +30% 

TN +24% +27% +28% +28% +31% +26% 

VA +29% +28% +20% +20% +35% +33% 

WV +26% +36% +35% +35% +36% +28% 

Aircraft 

(2275) 

Total +29% +31% +30% +30% +33% +31% 

AL +16% -8% -4% -4% -19% +10% 

FL +14% -8% -4% -4% -7% +9% 

GA +13% -8% -5% -5% -17% +9% 

KY +17% -10% -2% -2% -13% +12% 

MS +16% -9% -3% -3% -15% +11% 

NC +13% -8% -4% -4% -14% +9% 

SC +14% -9% -4% -4% -15% +10% 

TN +17% -10% -2% -2% -3% +12% 

VA +17% -9% -6% -6% -98% +11% 

WV +17% -10% -6% -6% -98% +12% 

Commercial 

Marine 

(2280) 

Total +15% -9% -3% -3% -14% +11% 

Military Marine VA +17% -10% -6% -6% -98% +12% 

(2283) Total +17% -10% -6% -6% -98% +12% 

AL +10% -24% -36% -36% -98% -13% 

FL +10% -24% -36% -36% -98% -13% 

GA +10% -20% -36% -36% -98% -12% 

KY +10% -23% -35% -35% -98% -13% 

MS +10% -24% -36% -36% -98% -13% 

NC +10% -24% -36% -36% -98% -13% 

SC +10% -24% -36% -36% -98% -13% 

TN +10% -15% -36% -36% -98% -13% 

VA +10% -14% -36% -36% -98% -11% 

WV +10% -18% -36% -36% -98% -12% 

Locomotives 

(2285) 

Total +10% -21% -36% -36% -98% -12% 

Grand Total +23% -12% -1% -1% -34% +11% 
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118,739

130,798

145,885

129,659

159,122

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

2002 2009 2018 2002 Prelim 2018 Prelim

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o

n

s

p

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r

Y

e

a

r

19,540 20,412

21,534 21,980

23,849

0

5,000

10,000

15,000

20,000

25,000

30,000

2002 2009 2018 2002 Prelim 2018 Prelim

T

o

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Y

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a

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Figure 2.3-2 Total Aircraft, Locomotive, and CMV CO Emissions (Base F)

Figure 2.3-3 Locomotive CO Emissions (Base F)
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420,228

397,462

367,975

455,067

395,049

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

500,000

2002 2009 2018 2002 Prelim 2018 Prelim

T

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187,044

169,635

147,252

211,588

167,783

0

50,000

100,000

150,000

200,000

250,000

2002 2009 2018 2002 Prelim 2018 Prelim

T

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Figure 2.3-4 Total Aircraft, Locomotive, and CMV NOx Emissions (Base F) 

Figure 2.3-5 Locomotive NOx Emissions (Base F) 
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22,823 21,946 22,557

100,452

128,715

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

2002 2009 2018 2002 Prelim 2018 Prelim

T

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5,815

4,440

3,744

6,118

3,947

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

2002 2009 2018 2002 Prelim 2018 Prelim

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Figure 2.3-6 Total Aircraft, Locomotive, and CMV PM10 Emissions (Base F) 

Figure 2.3-7 Locomotive PM10 Emissions (Base F) 
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5,232

3,995

3,368

5,505

3,552

0

1,000

2,000

3,000

4,000

5,000

6,000

2002 2009 2018 2002 Prelim 2018 Prelim

T

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21,170 20,413 21,015

73,099

92,207

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

2002 2009 2018 2002 Prelim 2018 Prelim

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Figure 2.3-8 Total Aircraft, Locomotive, and CMV PM2.5 Emissions (Base F) 

Figure 2.3-9 Locomotive PM2.5 Emissions (Base F) 
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14,022

2,343

333

14,947

1,553

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

2002 2009 2018 2002 Prelim 2018 Prelim

T

o

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52,931

36,126 35,132

57,062

41,284

0

10,000

20,000

30,000

40,000

50,000

60,000

2002 2009 2018 2002 Prelim 2018 Prelim

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Figure 2.3-10 Total Aircraft, Locomotive, and CMV SO2 Emissions (Base F) 

Figure 2.3-11 Locomotive SO2 Emissions (Base F)
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7,750

7,328

6,785

8,738

7,544

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2002 2009 2018 2002 Prelim 2018 Prelim

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24,881

26,148

27,709

26,877

29,228

22,000

23,000

24,000

25,000

26,000

27,000

28,000

29,000

30,000

2002 2009 2018 2002 Prelim 2018 Prelim

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Figure 2.3-12 Total Aircraft, Locomotive, and CMV VOC Emissions (Base F) 

Figure 2.3-13 Locomotive VOC Emissions (Base F) 
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Base G Revisions: 

Table 2.3-18 shows the Base G 2002 base year emissions for each State in the VISTAS region 

for aircraft, locomotives and CMV. Although some of these data are updated relative to those 

used as the basis of the Base F emissions forecasts, the methodology used to develop 2009 and 

2018 emissions forecasts for aircraft, locomotives, and CMV for Base G is identical to that used 

for Base F (as documented above). The only exceptions are as follows: 

(a) As indicated in the discussion of the Base F forecasts, the CAIR (growth rate) matching 

criteria were overridden for any record for which States provided local growth data. For 

Base F, only North Carolina provided such data. However, for Base G, Kentucky 

regulators provided growth data for aircraft emissions associated with 

Cincinnati/Northern Kentucky International Airport (located in Boone County, 

Kentucky). These data were applied to all pollutants and all aircraft types (i.e., military 

aircraft (SCC 2275001000), commercial aircraft (SCC 2275020000), general aviation 

aircraft (SCC 2275050000), and air taxi aircraft (SCC 2275060000)). Emissions forecasts 

for all aircraft operations in counties other than Boone continued to utilize the growth 

factors developed according to the CAIR matching criteria. Table 2.3-19 presents the 

locally generated growth factors applied in Kentucky. It should be recognized that 

although the locally provided growth factors presented in the table are significantly 

greater than those that would apply under the CAIR matching criteria, this is to be 

expected as local regulators noted a very significant decline in activity at the 

Cincinnati/Northern Kentucky International Airport in 2002 (relative to activity in 

preceding years). Moreover, this downward spike seems to have been alleviated since 

2002, so that the provided growth factors represent not only “routine” growth expected 

between 2002 and the two forecast years, but growth required to offset the temporary 

decline observed in 2002. 
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Table 2.3-18 Base G 2002 Aircraft, Locomotive, and Non-Recreational Marine Emissions 

(annual tons)

Source State CO NOx PM10 PM2.5 SO2 VOC 

AL 5,595 185 238 99 18 276 

FL 25,431 8,891 2,424 2,375 800 3,658 

GA 6,620 5,372 1,475 1,446 451 443 

KY 5,577 925 251 246 88 397 

MS 1,593 140 44 43 13 96 

NC 6,088 1,548 419 411 148 613 

SC 6,505 515 409 401 88 863 

TN 7,251 2,766 734 719 235 943 

VA 11,873 3,885 2,010 1,970 272 2,825 

WV 1,178 78 25 24 8 66 

Aircraft 

(2275) 

Total 77,712 24,305 8,029 7,734 2,121 10,179 

AL 1,196 9,218 917 844 3,337 737 

FL 5,888 44,817 1,936 1,781 6,683 1,409 

GA 1,038 7,875 334 307 1,173 246 

KY 6,607 50,267 2,246 2,066 9,608 1,569 

MS 5,688 43,233 1,903 1,751 7,719 1,351 

NC 599 4,547 193 178 690 142 

SC 1,067 8,100 343 316 1,205 253 

TN 3,624 27,555 1,217 1,120 4,974 860 

VA 972 2,775 334 307 359 483 

WV 1,528 11,586 487 448 525 362 

Commercial 

Marine 

(2280) 

Total 28,207 209,972 9,911 9,118 36,275 7,413 

Military Marine VA 110 313 25 23 27 48 

(2283) Total 110 313 25 23 27 48 

AL 3,518 26,623 592 533 1,446 1,365 

FL 1,006 9,969 247 222 605 404 

GA 2,654 26,733 664 598 1,622 1,059 

KY 2,166 21,811 542 488 1,321 867 

MS 2,302 23,267 578 520 1,429 899 

NC 1,638 16,502 410 369 1,001 654 

SC 1,160 11,690 291 261 710 462 

TN 2,626 25,627 633 570 1,439 1,041 

VA 1,186 11,882 1,529 1,375 3,641 492 

WV 1,311 13,224 329 296 808 517 

Locomotives 

(2285) 

Total 19,568 187,328 5,815 5,232 14,022 7,761 

Grand Total 125,597 421,918 23,780 22,107 52,444 25,401 
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Table 2.3-19 Locally Generated Growth Factors for Kentucky 

FIP 2009 Factor 2018 Factor 

21015 1.31 1.81 

Note: 

Growth factor = Year Emissions/2002 Emissions. 

Under CAIR approach, 2009 = 0.99 to 1.17. 

Under CAIR approach, 2018 = 0.97 to 1.40. 

(b) Because of the additional emissions records added in Alabama, as discussed in the Base 

G 2002 base year inventory section of this report, the total number of emissions records 

in the Base G 2009 and 2018 forecasts increased to 23,042 (as compared to 22,838 for 

Base F). The 23,042 data records for aircraft, locomotives, and CMV were assigned 

growth factors in accordance with the following breakdown: 

 72 records matched State-provided growth factors, 

 4,287 records matched using the CAIR-Primary criterion, 

 240 records matched using the CAIR-Secondary criterion, 

 7,511 records matched using the CAIR-Tertiary criterion, 

 720 records matched using the No T4-Primary criterion, 

 3,858 records matched using the No T4-Secondary criterion, and 

 6,354 records matched using the No T4-Tertiary criterion. 

Tables 2.3-20 and 2.3-21 present a summary of the resulting Base G 2009 and 2018 inventories, 

while Tables 2.3-22 and 2.3-23 present the associated change in emissions for each forecast 

inventory relative to the Base G 2002 base year VISTAS. As was the case with Base F, the larger 

reduction in CMV SO2 emissions in 2009 and 2018 (relative to 2002) for Virginia and West 

Virginia is notable relative to the other VISTAS States, but is attributable to a high diesel 

contribution to total CMV SO2 in the 2002 inventories for these two States. 

Figures 2.3-14 through 2.3-25 graphically depict the relationships between the various 

inventories, as revised through Base G. There are two figures for each pollutant, the first of 

which presents a comparison of total VISTAS regional emission estimates for aircraft, 

locomotives, and CMV, and the second of which presents total VISTAS region emission 

estimates for locomotives only. This two figure approach is intended to provide a more robust 

illustration of the differences between the various inventories, as some of the differences are less 

distinct when viewed through overall aggregate emissions totals. All of the figures include the 

following emissions estimates: 
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 The Base G 2002 base year VISTAS emissions inventory (labeled as “2002”), 

 The pre-Base F 2002 base year VISTAS emissions inventory (labeled as “2002 

Prelim”), 

 The Base G 2009 VISTAS emissions inventory developed using growth rates derived 

from 1996 and 2020 EPA CAIR data (labeled as “2009”), 

 The Base G 2018 VISTAS emissions inventory developed using growth rates derived 

from 1996 and 2020 EPA CAIR data (labeled as “2018”), and 

 The pre-Base F 2018 VISTAS emissions inventory estimates developed using growth 

rates derived from 1996, 2010, 2015, and 2020 EPA CAIR data (labeled as “2018 

Prelim”). 

All 12 figures generally illustrate a reduction in emissions estimates between the pre-Base F 

2002 emission estimates published in February 2004 and the Base G 2002 base year emission 

estimates. This reduction generally results from emission updates reflected in the Base F State 

CERR submittals, although the major differences in aggregate PM emission estimates are driven 

to a greater extent by modifications in the methodology used to estimate aircraft PM in the 

Base F revisions to the 2002 Base F base year inventory (as documented under the base year 

inventory section of this report). 
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Table 2.3-20 Base G 2009 Aircraft, Locomotive, and Non-Recreational Marine Emissions 

(annual tons) -- Based on Growth Using 1996 and 2020 EPA Inventories

Source State CO NOx PM10 PM2.5 SO2 VOC 

AL 6,265 213 292 116 21 309 

FL 29,258 10,316 2,812 2,756 928 4,235 

GA 7,635 6,233 1,712 1,678 523 512 

KY 6,959 1,135 307 301 108 487 

MS 1,765 162 51 50 16 108 

NC 6,991 1,795 486 477 171 709 

SC 7,372 559 446 437 98 975 

TN 8,020 3,096 824 807 268 1,050 

VA 13,141 4,244 2,124 2,082 306 3,153 

WV 1,312 91 28 28 9 74 

Aircraft 

(2275) 

Total 88,716 27,844 9,083 8,732 2,447 11,612 

AL 1,280 8,888 872 802 2,753 768 

FL 6,236 43,198 1,838 1,691 5,864 1,467 

GA 1,097 7,599 317 291 974 256 

KY 7,087 48,039 2,158 1,985 8,350 1,649 

MS 6,074 41,437 1,821 1,676 6,587 1,415 

NC 634 4,386 184 169 584 148 

SC 1,133 7,796 326 300 1,012 264 

TN 3,887 26,333 1,168 1,074 4,512 904 

VA 1,042 2,662 312 286 61 506 

WV 1,638 11,073 455 419 89 381 

Commercial 

Marine 

(2280) 

Total 30,108 201,412 9,450 8,693 30,786 7,759 

Military Marine VA 118 299 23 21 5 50 

(2283) Total 118 299 23 21 5 50 

AL 3,677 23,783 452 406 242 1,289 

FL 1,052 8,905 189 170 101 382 

GA 2,769 24,398 507 456 271 1,003 

KY 2,264 19,597 415 374 221 819 

MS 2,406 20,785 441 397 239 849 

NC 1,690 14,662 311 279 165 613 

SC 1,213 10,443 222 200 119 437 

TN 2,745 23,924 483 435 240 984 

VA 1,236 11,134 1,167 1,050 608 467 

WV 1,369 12,177 251 226 135 489 

Locomotives 

(2285) 

Total 20,420 169,808 4,437 3,993 2,341 7,333 

Grand Total 139,362 399,364 22,994 21,440 35,578 26,754
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Table 2.3-21 Base G 2018 Aircraft, Locomotive, and Non-Recreational Marine Emissions 

(annual tons) -- Based on Growth Using 1996 and 2020 EPA Inventories

Source State CO NOx PM10 PM2.5 SO2 VOC 

AL 7,126 249 361 139 24 352

FL 34,178 12,147 3,312 3,246 1,093 4,976

GA 8,939 7,340 2,016 1,976 616 601

KY 9,078 1,446 391 383 138 623

MS 1,986 190 60 58 18 122

NC 8,150 2,114 572 561 202 831

SC 8,487 616 493 484 112 1,119

TN 9,009 3,519 939 921 309 1,187

VA 14,770 4,706 2,271 2,226 349 3,574

WV 1,484 106 33 33 10 85

Aircraft 

(2275) 

Total 103,206 32,435 10,450 10,027 2,871 13,472

AL 1,388 8,464 880 809 2,715 809

FL 6,684 41,117 1,853 1,705 6,248 1,543

GA 1,174 7,246 319 293 976 269

KY 7,703 45,174 2,199 2,023 8,383 1,752

MS 6,571 39,129 1,850 1,702 6,556 1,498

NC 678 4,179 185 170 596 155

SC 1,217 7,406 329 303 1,027 278

TN 4,225 24,763 1,190 1,095 4,808 960

VA 1,133 2,517 314 289 9 537

WV 1,781 10,412 459 422 13 404

Commercial 

Marine 

(2280) 

Total 32,554 190,407 9,578 8,811 31,330 8,205

Military Marine VA 128 282 23 21 1 53

(2283) Total 128 282 23 21 1 53

AL 3,881 20,131 381 343 34 1,192

FL 1,110 7,538 159 143 14 353

GA 2,917 21,395 427 385 38 932

KY 2,389 16,751 352 317 31 757

MS 2,540 17,594 372 335 34 785

NC 1,782 12,539 263 237 23 570

SC 1,280 8,840 187 168 17 404

TN 2,897 21,735 407 367 34 910

VA 1,300 10,173 983 885 86 436

WV 1,444 10,831 212 190 19 453

Locomotives 

(2285) 

Total 21,539 147,527 3,743 3,368 332 6,792

Grand Total 157,427 370,651 23,794 22,227 34,534 28,522 
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Table 2.3-22 Change in Emissions between 2009 Base G and 2002 Base F Inventories 

(Based on Growth Using 1996 and 2020 EPA Inventories)

Source State CO NOx PM10 PM2.5 SO2 VOC 

AL +12% +15% +23% +18% +16% +12%

FL +15% +16% +16% +16% +16% +16%

GA +15% +16% +16% +16% +16% +16%

KY +25% +23% +23% +23% +23% +23%

MS +11% +16% +15% +15% +16% +12%

NC +15% +16% +16% +16% +16% +16%

SC +13% +9% +9% +9% +12% +13%

TN +11% +12% +12% +12% +14% +11%

VA +11% +9% +6% +6% +12% +12%

WV +11% +16% +15% +15% +16% +12%

Aircraft 

(2275) 

Total +14% +15% +13% +13% +15% +14%

AL +7% -4% -5% -5% -18% +4%

FL +6% -4% -5% -5% -12% +4%

GA +6% -3% -5% -5% -17% +4%

KY +7% -4% -4% -4% -13% +5%

MS +7% -4% -4% -4% -15% +5%

NC +6% -4% -5% -5% -15% +4%

SC +6% -4% -5% -5% -16% +4%

TN +7% -4% -4% -4% -9% +5%

VA +7% -4% -7% -7% -83% +5%

WV +7% -4% -7% -7% -83% +5%

Commercial 

Marine 

(2280) 

Total +7% -4% -5% -5% -15% +5%

Military Marine VA +7% -4% -7% -7% -83% +5%

(2283) Total +7% -4% -7% -7% -83% +5%

AL +5% -11% -24% -24% -83% -6%

FL +5% -11% -24% -24% -83% -6%

GA +4% -9% -24% -24% -83% -5%

KY +5% -10% -23% -23% -83% -6%

MS +5% -11% -24% -24% -83% -6%

NC +3% -11% -24% -24% -83% -6%

SC +5% -11% -24% -24% -83% -6%

TN +5% -7% -24% -24% -83% -6%

VA +4% -6% -24% -24% -83% -5%

WV +4% -8% -24% -24% -83% -5%

Locomotives 

(2285) 

Total +4% -9% -24% -24% -83% -6%

Grand Total +11% -5% -3% -3% -32% +5%
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Table 2.3-23 Change in Emissions between 2018 Base G and 2002 Base F Inventories 

(Based on Growth Using 1996 and 2020 EPA Inventories)

Source State CO NOx PM10 PM2.5 SO2 VOC 

AL +27% +35% +52% +41% +36% +28%

FL +34% +37% +37% +37% +37% +36%

GA +35% +37% +37% +37% +37% +36%

KY +63% +56% +56% +56% +56% +57%

MS +25% +36% +35% +35% +36% +27%

NC +34% +37% +36% +36% +37% +36%

SC +30% +20% +21% +21% +27% +30%

TN +24% +27% +28% +28% +31% +26%

VA +24% +21% +13% +13% +28% +27%

WV +26% +36% +35% +35% +36% +28%

Aircraft 

(2275) 

Total +33% +33% +30% +30% +35% +32%

AL +16% -8% -4% -4% -19% +10%

FL +14% -8% -4% -4% -7% +9%

GA +13% -8% -5% -5% -17% +9%

KY +17% -10% -2% -2% -13% +12%

MS +16% -9% -3% -3% -15% +11%

NC +13% -8% -4% -4% -14% +9%

SC +14% -9% -4% -4% -15% +10%

TN +17% -10% -2% -2% -3% +12%

VA +17% -9% -6% -6% -98% +11%

WV +17% -10% -6% -6% -98% +12%

Commercial 

Marine 

(2280) 

Total +15% -9% -3% -3% -14% +11%

Military Marine VA +17% -10% -6% -6% -98% +12%

(2283) Total +17% -10% -6% -6% -98% +12%

AL +10% -24% -36% -36% -98% -13%

FL +10% -24% -36% -36% -98% -13%

GA +10% -20% -36% -36% -98% -12%

KY +10% -23% -35% -35% -98% -13%

MS +10% -24% -36% -36% -98% -13%

NC +9% -24% -36% -36% -98% -13%

SC +10% -24% -36% -36% -98% -13%

TN +10% -15% -36% -36% -98% -13%

VA +10% -14% -36% -36% -98% -11%

WV +10% -18% -36% -36% -98% -12%

Locomotives 

(2285) 

Total +10% -21% -36% -36% -98% -12%

Grand Total +25% -12% +0% +1% -34% +12%
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125,597

139,362

157,427

129,659

159,122

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

2002 2009 2018 2002 Prelim 2018 Prelim

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o

n

s

p

e

r

Y

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a

r

19,568 20,420

21,539 21,980

23,849

0

5,000

10,000

15,000

20,000

25,000

30,000

2002 2009 2018 2002 Prelim 2018 Prelim

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o

n

s

p

e

r

Y

e

a

r

Figure 2.3-14 Total Aircraft, Locomotive, and CMV CO Emissions (Base G)

Figure 2.3-15 Locomotive CO Emissions (Base G)
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421,918

399,364

370,651

455,067

395,049

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

450,000

500,000

2002 2009 2018 2002 Prelim 2018 Prelim

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187,328

169,808

147,527

211,588

167,783

0

50,000

100,000

150,000

200,000

250,000

2002 2009 2018 2002 Prelim 2018 Prelim

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o

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Y

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a

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Figure 2.3-16 Total Aircraft, Locomotive, and CMV NOx Emissions (Base G) 

Figure 2.3-17 Locomotive NOx Emissions (Base G) 
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23,780 22,994 23,794

100,452

128,715

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

2002 2009 2018 2002 Prelim 2018 Prelim

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5,815

4,437

3,743

6,118

3,947

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

2002 2009 2018 2002 Prelim 2018 Prelim

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Y

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a

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Figure 2.3-18 Total Aircraft, Locomotive, and CMV PM10 Emissions (Base G) 

Figure 2.3-19 Locomotive PM10 Emissions (Base G) 
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22,107 21,440 22,227

73,099

92,207

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

2002 2009 2018 2002 Prelim 2018 Prelim

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o

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s

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Y

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a

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5,232

3,993

3,368

5,505

3,552

0

1,000

2,000

3,000

4,000

5,000

6,000

2002 2009 2018 2002 Prelim 2018 Prelim

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o

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Y

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a

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Figure 2.3-20 Total Aircraft, Locomotive, and CMV PM2.5 Emissions (Base G) 

Figure 2.3-21 Locomotive PM2.5 Emissions (Base G) 
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52,444

35,578 34,534

57,062

41,284

0

10,000

20,000

30,000

40,000

50,000

60,000

2002 2009 2018 2002 Prelim 2018 Prelim

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o

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Y

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a

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14,022

2,341

332

14,947

1,553

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

2002 2009 2018 2002 Prelim 2018 Prelim

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Figure 2.3-22 Total Aircraft, Locomotive, and CMV SO2 Emissions (Base G) 

Figure 2.3-23 Locomotive SO2 Emissions (Base G)
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25,401

26,754

28,522

26,877

29,228

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

2002 2009 2018 2002 Prelim 2018 Prelim

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7,761

7,333

6,792

8,738

7,544

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

2002 2009 2018 2002 Prelim 2018 Prelim

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Figure 2.3-24 Total Aircraft, Locomotive, and CMV VOC Emissions (Base G) 

Figure 2.3-25 Locomotive VOC Emissions (Base G) 
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2.3.4.3 Emissions from NONROAD Model Sources in Illinois, Indiana, and Ohio 

Base G projection inventories for 2009 and 2018 for NONROAD model sources in the states of 

Illinois, Indiana, and Ohio were produced using a methodology identical to that employed to 

develop a Base G 2002 base year inventory for the same states (as documented earlier in this 

report). This method consists of the extraction of a complete set of county-level input data 

applicable to each of the three states (in each of the two projection years) from the latest version 

of the EPA’s NMIM model. This includes appropriate consideration of all non-default NMIM 

input files generated by the Midwest Regional Planning Organization as documented earlier in 

the discussion of the Base G 2002 base year inventory. These input data were then assembled 

into appropriate input files for the Final NONROAD2005 model and emission estimates were 

produced using the same procedure employed for the VISTAS region. 

Changes noted between the base year (2002) and forecast year (2009 and 2018) input data 

extracted from NMIM include differences in gasoline vapor pressure, gasoline sulfur content, 

and diesel sulfur content in most counties. All temperature data (minimum, maximum, and 

average daily temperatures) was constant across years. 

As described in the discussion of the Base G 2002 base year inventory, counties in the three 

states were grouped for modeling purposes using a temperature aggregation scheme that allowed 

for county-specific temperature variations of no more that 2 oF from group average temperatures 

(for all temperature inputs). The same grouping scheme was applied to projection year modeling, 

so that Illinois emissions were modeled using 12 county groups, Indiana emissions were modeled 

using 9 county groups, and Ohio emissions were modeled using 10 county groups. Thus, 31 

iterations of NONROAD2002 were required per season per projection year, as compared to the 

53 iterations per season per projection year required for the VISTAS region. 

As was also described in the discussion of the Base G 2002 base year inventory, several 

non-default equipment population, growth, activity, seasonal distribution, and county allocation 

files are assigned by NMIM model inputs for these counties. As was the case for the base year 

inventory development, these same non-default assignments were retained for both 

projection inventories. 

2.3.4.4 Differences between 2009/2018 

Methodologically, there was no difference in the way that 2009 and 2018 emissions were 

calculated for non-road mobile sources. The actual value of the growth factors were different for 

each type of mobile source considered, but the calculation methods were identical. 
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2.3.5 Quality Assurance steps 

Throughout the inventory development process, quality assurance steps were performed to 

ensure that no double counting of emissions occurred, to ensure that a full and complete 

inventory was developed for VISTAS, and to make sure that projection calculations were 

working correctly. Quality assurance was an important component to the inventory development 

process and MACTEC performed the following QA steps on mobile source components of the 

2009 and revised 2018 projection inventories: 

1. All final files (NONROAD only) were run through EPA’s Format and Content 

checking software. Input data files for MOBILE and VMT growth estimates were 

reviewed by the corresponding SIWG and by the VISTAS Emission Inventory 

Technical Advisor. 

2. SCC level emission summaries were prepared and evaluated to ensure that emissions 

were consistent and that there were no missing sources (NONROAD only). 

3. Tier comparisons (by pollutant) were developed between the 2002 base year 

inventory and the 2009 and 2018 projection inventories (NONROAD only). Total 

VISTAS level summaries by pollutant were developed for these sources to compare 

Base F and Base G emission levels. 

4. Data product summaries were provided to both the VISTAS Emission Inventory 

Technical Advisor and to the SIWG representatives for review and comment. 

Changes based on these comments were implemented in the files. 

5. Version numbering was used for all inventory files developed. The version 

numbering process used a decimal system to track major and minor changes. For 

example, a major change would result in a version going from 1.0 to 2.0. A minor 

change would cause a version number to go from 1.0 to 1.1. Minor changes resulting 

from largely editorial changes would result in a change from 1.00 to 1.01. 
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Appendix A: 

STATE EMISSION TOTALS BY POLLUTANT AND SECTOR 
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Appendix A 

199

Annual CO Emissions by Source Sector

0

1,000,0002,000,0003,000,0004,000,0005,000,0006,000,0007,000,0008,000,000

AL

FL

GA

KY

MS

NC

SC

TN

VA

W

Tons per year

2002 Actual EGU and Fires

2002 Typical EGU and Fires

2009

2018
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Annual CO Emissions by Source Sector 

Name EGU NONEGU ONROAD NONROAD AREA FIRES YEAR

11,279 174,271 1,321,528 414,385 83,958 474,959 2002 Actual 

11,460 174,260 1,321,528 414,385 83,958 514,120 2002 Typical 

AL 14,986 180,369 915,647 454,686 66,654 534,873 2009 

24,342 201,663 676,210 488,924 59,626 535,658 2018 

57,113 81,933 4,550,447 1,920,729 71,079 790,620 2002 Actual 

55,899 81,928 4,550,447 1,920,729 71,079 923,310 2002 Typical 

FL 71,072 87,661 3,352,509 2,104,920 57,011 923,310 2009 

85,495 97,438 2,554,160 2,323,327 53,903 923,310 2018 

9,712 130,850 2,735,968 791,158 108,083 654,411 2002 Actual 

9,650 130,850 2,735,968 791,158 108,083 620,342 2002 Typical 

GA 23,721 147,427 1,983,803 882,970 94,130 637,177 2009 

44,269 167,904 1,476,981 973,872 93,827 637,177 2018 

12,619 109,936 1,230,148 325,993 66,752 8,703 2002 Actual 

12,607 109,936 1,230,148 325,993 66,752 24,900 2002 Typical 

KY 15,812 122,024 963,762 357,800 57,887 31,810 2009 

17,144 139,437 807,536 381,215 54,865 33,296 2018 

5,303 54,568 864,290 236,752 37,905 13,209 2002 Actual 

5,219 54,568 864,290 236,752 37,905 14,353 2002 Typical 

MS 7,116 57,749 609,972 257,453 27,184 48,160 2009 

17,348 65,884 445,493 270,726 22,099 50,037 2018 

13,885 50,576 2,873,992 808,231 345,315 34,515 2002 Actual 

14,074 50,576 2,873,992 808,231 345,315 71,970 2002 Typical 

NC 14,942 53,744 1,991,708 887,605 301,163 96,258 2009 

19,870 62,197 1,362,214 960,709 290,809 111,266 2018 

6,990 56,315 1,241,359 413,964 113,714 248,341 2002 Actual 

6,969 56,315 1,241,359 413,964 113,714 253,005 2002 Typical 

SC 11,643 59,934 889,957 448,625 90,390 282,307 2009 

14,975 68,415 663,493 481,332 83,167 282,307 2018 

7,084 115,264 1,917,842 505,163 89,828 4,302 2002 Actual 

6,787 115,264 1,917,842 505,163 89,828 10,124 2002 Typical 

TN 7,214 119,216 1,338,016 554,121 74,189 17,372 2009 

7,723 140,556 976,634 593,100 68,809 18,860 2018 

6,892 63,796 2,163,259 660,105 155,873 15,625 2002 Actual 

6,797 63,784 2,163,259 660,105 155,873 12,611 2002 Typical 

VA 12,535 68,326 1,453,946 726,815 128,132 21,130 2009 

18,850 76,846 1,075,104 797,683 121,690 26,923 2018 

10,341 89,879 533,471 133,113 39,546 6,738 2002 Actual 

10,117 89,878 533,471 133,113 39,546 2,652 2002 Typical 

WV 11,493 93,839 365,549 152,862 31,640 3,949 2009 

12,397 111,302 274,804 167,424 28,773 5,013 2018 
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Annual NH3 Emissions by Source Sector

0

50,000

100,000150,000200,000250,000

AL

FL

GA

KY

MS

NC

SC

TN

VA

W

Tons per year

2002 Actual EGU and Fires

2002 Typical EGU and Fires

2009

2018
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Annual NH3 Emissions by Source Sector 

Name EGU NONEGU ONROAD NONROAD AREA FIRES YEAR 

317 1,883 5,588 33 58,318 1,689 2002 Actual 

239 1,883 5,588 33 58,318 1,957 2002 Typical 

359 2,132 6,364 36 64,268 2,050 2009 

AL 

1,072 2,464 7,298 42 71,915 2,054 2018 

234 1,423 18,114 134 37,446 3,102 2002 Actual 

222 1,423 18,114 134 37,446 3,157 2002 Typical 

FL 1,629 1,544 21,781 148 38,616 3,157 2009 

2,976 1,829 26,163 171 40,432 3,157 2018 

83 3,613 10,546 60 80,913 2,578 2002 Actual 

86 3,613 10,546 60 80,913 2,153 2002 Typical 

GA 686 3,963 12,687 68 89,212 2,229 2009 

1,677 4,797 14,873 79 99,885 2,229 2018 

326 674 5,055 31 51,135 39 2002 Actual 

321 674 5,055 31 51,135 112 2002 Typical 

KY 400 760 5,796 34 53,005 143 2009 

476 901 7,811 40 55,211 150 2018 

190 1,169 3,585 23 58,721 59 2002 Actual 

198 1,169 3,585 23 58,721 65 2002 Typical 

MS 334 668 4,035 25 63,708 217 2009 

827 764 4,566 29 69,910 225 2018 

54 1,179 9,702 65 161,860 155 2002 Actual 

55 1,179 9,702 65 161,860 324 2002 Typical 

NC 445 1,285 11,825 72 170,314 433 2009 

663 1,465 14,065 83 180,866 501 2018 

142 1,411 4,694 33 28,166 980 2002 Actual 

141 1,411 4,694 33 28,166 908 2002 Typical 

SC 370 1,578 5,523 36 30,555 1,039 2009 

625 1,779 6,473 41 33,496 1,039 2018 

204 1,613 6,625 43 34,393 19 2002 Actual 

197 1,613 6,625 43 34,393 46 2002 Typical 

227 1,840 7,782 48 35,253 78 2009 

TN 

241 2,213 9,021 55 36,291 85 2018 

127 3,104 7,852 48 43,905 70 2002 Actual 

130 3,104 7,852 48 43,905 57 2002 Typical 

694 3,045 9,086 53 46,639 95 2009 

VA 

606 3,604 10,624 61 50,175 121 2018 

121 332 1,908 9 9,963 30 2002 Actual 

121 332 1,908 9 9,963 12 2002 Typical 

330 314 2,148 11 10,625 18 2009 

WV 

143 378 2,497 13 11,504 23 2018 
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Appendix A 

203

Annual NOx Emissions by Source Sector

0

200,000400,000600,000800,000

1,000,0001,200,000

AL

FL

GA

KY

MS

NC

SC

TN

VA

W

Tons per year

2002 Actual EGU and Fires

2002 Typical EGU and Fires

2009

2018

v
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Appendix A MACTEC, Inc. 204

Annual NOx Emissions by Source Sector 

Name EGU NONEGU ONROAD NONROAD AREA FIRES YEAR 

161,038 83,310 158,212 65,366 23,444 10,728 2002 Actual 

154,704 83,302 158,212 65,366 23,444 11,456 2002 Typical 

AL 82,305 69,409 101,831 56,862 23,930 11,901 2009 

64,358 77,960 47,298 43,799 25,028 11,918 2018 

257,677 45,156 465,640 180,627 28,872 15,942 2002 Actual 

255,678 45,150 465,640 180,627 28,872 19,791 2002 Typical 

FL 132,535 47,125 315,840 163,794 28,187 19,791 2009 

87,645 52,959 150,180 127,885 30,708 19,791 2018 

147,517 49,251 307,732 97,961 36,142 14,203 2002 Actual 

148,126 49,251 307,732 97,961 36,142 13,882 2002 Typical 

GA 98,497 50,353 209,349 85,733 37,729 14,243 2009 

69,856 55,824 102,179 64,579 41,332 14,243 2018 

198,817 38,392 156,417 104,571 39,507 187 2002 Actual 

201,928 38,434 156,417 104,571 39,507 534 2002 Typical 

KY 97,263 37,758 101,182 94,752 42,088 682 2009 

64,378 41,034 52,263 79,392 44,346 714 2018 

43,135 61,526 111,914 88,787 4,200 283 2002 Actual 

40,433 61,553 111,914 88,787 4,200 308 2002 Typical 

MS 47,276 56,398 70,743 80,567 4,249 1,033 2009 

21,535 61,252 30,619 68,252 4,483 1,073 2018 

151,850 44,929 327,329 84,284 36,550 740 2002 Actual 

148,812 44,929 327,329 84,284 36,550 1,544 2002 Typical 

NC 66,521 34,768 201,609 70,997 39,954 2,065 2009 

61,110 37,802 87,791 49,046 43,865 2,387 2018 

88,241 42,153 140,489 50,249 19,332 4,932 2002 Actual 

88,528 42,153 140,489 50,249 19,332 5,270 2002 Typical 

48,668 39,368 92,499 43,235 19,360 5,899 2009 

 

 

SC 

51,751 43,331 43,490 31,758 20,592 5,899 2018 

157,307 64,344 238,577 96,827 17,844 92 2002 Actual 

152,137 64,344 238,577 96,827 17,844 217 2002 Typical 

TN 66,405 57,514 151,912 86,641 18,499 373 2009 

31,715 62,519 69,385 70,226 19,597 405 2018 

86,886 60,415 222,374 63,219 51,418 335 2002 Actual 

85,081 60,390 222,374 63,219 51,418 271 2002 Typical 

VA 64,358 51,001 134,232 54,993 52,618 453 2009 

64,344 55,734 63,342 40,393 56,158 578 2018 

230,977 46,612 58,999 33,239 12,687 145 2002 Actual 

222,437 46,618 58,999 33,239 12,687 57 2002 Typical 

WV 85,476 38,023 35,635 30,133 13,439 85 2009 

51,474 43,280 17,247 25,710 14,828 108 2018 
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Appendix A 

205

Annual PM10 Emissions by Source Sector

0

200,000400,000600,000800,000

1,000,0001,200,000

AL

FL

GA

KY

MS

NC

SC

TN

VA

W

Tons per year

2002 Actual EGU and Fires

2002 Typical EGU and Fires

2009

2018
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Appendix A MACTEC, Inc. 206

Annual PM10 Emissions by Source Sector 

Name EGU NONEGU ONROAD NONROAD AREA FIRES YEAR 

7,646 25,240 3,903 4,787 393,588 47,237 2002 Actual 

7,845 25,239 3,903 4,787 393,588 50,833 2002 Typical 

6,969 25,421 3,171 4,027 413,020 52,851 2009 

AL 

7,822 29,889 2,410 3,041 445,256 52,927 2018 

21,387 35,857 11,275 18,281 443,346 85,263 2002 Actual 

21,391 35,856 11,275 18,281 443,346 98,470 2002 Typical 

20,182 39,947 9,911 15,613 503,230 98,470 2009 

FL 

12,791 46,492 8,268 12,497 578,516 98,470 2018 

11,224 21,610 7,246 8,618 695,414 65,227 2002 Actual 

11,467 21,610 7,246 8,618 695,414 62,336 2002 Typical 

17,891 23,103 6,072 7,521 776,411 63,973 2009 

GA 

20,732 27,273 4,844 6,015 880,199 63,973 2018 

4,701 16,626 3,723 6,425 233,559 846 2002 Actual 

4,795 16,626 3,723 6,425 233,559 2,421 2002 Typical 

6,463 17,174 2,976 5,544 242,177 3,093 2009 

KY 

6,694 20,153 2,580 4,556 256,052 3,237 2018 

1,633 19,472 2,859 5,010 343,377 1,284 2002 Actual 

1,706 19,469 2,859 5,010 343,377 1,396 2002 Typical 

5,182 19,245 2,275 4,270 356,324 4,683 2009 

MS 

7,412 22,837 1,624 3,452 375,495 4,865 2018 

22,754 13,838 6,579 7,348 280,379 3,356 2002 Actual 

22,994 13,838 6,579 7,348 280,379 6,998 2002 Typical 

22,152 13,910 5,572 6,055 292,443 9,359 2009 

NC 

35,275 15,737 4,392 4,298 315,294 10,819 2018 

21,400 14,142 3,452 4,152 260,858 25,968 2002 Actual 

21,827 14,142 3,452 4,152 260,858 26,304 2002 Typical 

20,041 12,959 2,862 3,471 278,299 29,153 2009 

SC 

27,640 14,674 2,184 2,617 304,251 29,153 2018 

14,640 35,174 5,371 6,819 212,554 418 2002 Actual 

13,866 35,174 5,371 6,819 212,554 984 2002 Typical 

15,608 34,581 4,206 5,877 226,098 1,689 2009 

TN 

15,941 41,999 3,092 4,672 246,252 1,834 2018 

3,960 13,252 4,549 8,728 237,577 1,519 2002 Actual 

3,892 13,252 4,549 8,728 237,577 1,226 2002 Typical 

5,606 13,046 3,747 7,510 252,488 2,054 2009 

VA 

12,551 15,111 3,212 6,208 275,351 2,618 2018 

4,573 17,503 1,381 1,850 115,346 655 2002 Actual 

4,472 17,503 1,381 1,850 115,346 258 2002 Typical 

5,657 11,882 1,068 1,640 115,089 384 2009 

WV 

5,784 14,202 819 1,292 121,549 487 2018 
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Appendix A 

207

Annual PM2.5 Emissions by Source Sector

0

50,000

100,000150,000200,000250,000

AL

FL

GA

KY

MS

NC

SC

TN

VA

W

Tons per year

2002 Actual EGU and Fires

2002 Typical EGU and Fires

2009

2018
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Appendix A MACTEC, Inc. 208

Annual PM2.5 Emissions by Source Sector 

Name EGU NONEGU ONROAD NONROAD AREA FIRES YEAR 

 4,113 19,178 2,799 4,502 56,654 42,041 2002 Actual 

 4,176 19,177 2,799 4,502 56,654 44,812 2002 Typical 

AL 3,921 19,230 2,032 3,776 58,699 46,543 2009 

 4,768 22,584 1,192 2,835 62,323 46,608 2018 

 15,643 30,504 7,868 17,415 58,878 75,717 2002 Actual 

 15,575 30,504 7,868 17,415 58,878 88,756 2002 Typical 

FL 14,790 34,019 6,173 14,866 64,589 88,756 2009 

 9,417 39,486 4,038 11,868 72,454 88,756 2018 

 4,939 17,462 5,168 8,226 103,794 57,293 2002 Actual 

 5,070 17,462 5,168 8,226 103,794 55,712 2002 Typical 

GA 10,907 18,982 3,840 7,175 112,001 57,116 2009 

 13,881 22,416 2,380 5,730 123,704 57,116 2018 

 2,802 11,372 2,697 6,046 45,453 726 2002 Actual 

 2,847 11,372 2,697 6,046 45,453 2,076 2002 Typical 

KY 4,279 11,686 1,920 5,203 46,243 2,653 2009 

 4,434 13,739 1,272 4,256 47,645 2,777 2018 

 1,138 9,906 2,112 4,690 50,401 1,102 2002 Actual 

 1,147 9,902 2,112 4,690 50,401 1,197 2002 Typical 

MS 4,996 9,199 1,508 3,985 51,661 4,016 2009 

 7,252 10,719 819 3,203 53,222 4,173 2018 

 16,498 10,500 4,623 7,005 64,052 2,878 2002 Actual 

 16,623 10,500 4,623 7,005 64,052 6,002 2002 Typical 

NC 15,949 10,458 3,493 5,760 69,457 8,027 2009 

 28,137 11,825 2,123 4,069 71,262 9,279 2018 

 17,154 10,245 2,501 3,945 40,291 22,953 2002 Actual 

 17,521 10,245 2,501 3,945 40,291 23,511 2002 Typical 

SC 16,548 9,048 1,855 3,294 41,613 25,955 2009 

 23,794 10,699 1,087 2,474 44,319 25,955 2018 

 12,166 27,807 3,949 6,458 42,566 359 2002 Actual 

 11,491 27,807 3,949 6,458 42,566 844 2002 Typical 

TN 13,092 27,367 2,751 5,557 44,124 1,449 2009 

 13,387 33,293 1,544 4,403 46,692 1,573 2018 

 2,606 10,165 3,102 8,288 43,989 1,303 2002 Actual 

 2,650 10,165 3,102 8,288 43,989 1,052 2002 Typical 

VA 4,165 9,988 2,241 7,136 44,514 1,762 '2009 

 10,773 11,605 1,543 5,891 46,697 2,245 2018 

 2,210 13,313 995 1,728 21,049 562 2002 Actual 

 2,163 13,313 995 1,728 21,049 221 2002 Typical 

WV 2,940 7,638 684 1,528 20,664 329 2009 

 3,116 9,124 405 1,198 21,490 418 2018 
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Appendix A 

209

Annual SO2 Emissions by Source Sector

0

100,000200,000300,000400,000500,000600,000700,000

AL

FL

GA

KY

MS

NC

SC

TN

VA

W

Tons per year

2002 Actual EGU and Fires

2002 Typical EGU and Fires

2009

2018
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Appendix A MACTEC, Inc. 210

Annual SO2 Emissions by Source Sector 

Name EGU NONEGU ONROAD NONROAD AREA FIRES YEAR 

447,828 96,481 6,900 7,584 52,253 2,208 2002 Actual 

423,736 96,481 6,900 7,584 52,253 2,559 2002 Typical 

AL 378,052 101,246 810 3,471 48,228 2,681 2009 

135,851 103,303 720 2,818 50,264 2,686 2018 

453,631 65,090 20,915 20,614 40,491 4,057 2002 Actual 

444,383 65,090 20,915 20,614 40,491 4,129 2002 Typical 

FL 291,831 65,651 2,612 8,967 36,699 4,129 2009 

194,028 71,810 2,533 7,536 38,317 4,129 2018 

514,952 53,774 12,184 9,005 57,559 3,372 2002 Actual 

517,633 53,778 12,184 9,005 57,559 2,815 2002 Typical 

GA 408,679 53,983 1,585 2,725 57,696 2,914 2009 

68,515 59,343 1,457 1,709 59,729 2,914 2018 

484,057 34,029 6,308 14,043 41,805 51 2002 Actual 

495,153 34,029 6,308 14,043 41,805 146 2002 Typical 

KY 271,669 36,418 759 9,180 43,087 187 2009 

222,102 40,682 763 8,592 44,186 196 2018 

67,429 35,960 4,614 11,315 771 78 2002 Actual 

60,086 35,954 4,614 11,315 771 84 2002 Typical 

MS 76,646 25,564 537 7,191 753 283 2009 

15,213 25,674 440 6,638 746 294 2018 

477,990 44,123 12,420 7,693 5,412 203 2002 Actual 

478,488 44,123 12,420 7,693 5,412 423 2002 Typical 

NC 242,286 42,536 1,503 1,892 5,751 566 2009 

120,165 46,314 1,481 905 6,085 655 2018 

206,399 53,518 5,972 4,866 12,900 1,281 2002 Actual 

210,272 53,518 5,972 4,866 12,900 1,187 2002 Typical 

SC 129,122 47,193 721 1,701 13,051 1,359 2009 

95,377 52,410 643 1,198 13,457 1,359 2018 

334,151 79,604 9,226 10,441 29,917 25 2002 Actual 

320,146 79,604 9,226 10,441 29,917 60 2002 Typical 

TN 255,410 64,964 1,076 5,651 30,577 102 2009 

112,672 56,682 948 5,207 31,962 111 2018 

241,204 63,903 8,294 8,663 105,890 92 2002 Actual 

233,691 63,900 8,294 8,663 105,890 74 2002 Typical 

VA 174,777 58,039 1,079 1,707 105,984 124 2009 

98,988 57,790 1,043 507 109,380 158 2018 

516,084 54,070 2,464 2,112 11,667 40 2002 Actual 

500,381 54,077 2,464 2,112 11,667 16 2002 Typical 

WV 268,952 55,598 279 359 12,284 23 2009 

106,199 61,702 253 56 12,849 29 2018 
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Appendix A 

211

Annual VOC Emissions by Source Sector

0

200,000400,000600,000800,000

1,000,0001,200,0001,400,000

AL

FL

GA

KY

MS

NC

SC

TN

VA

W

Tons per year

2002 Actual EGU and Fires

2002 Typical EGU and Fires

2009

2018
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Appendix A MACTEC, Inc. 212

Annual VOC Emissions by Source Sector 

Name EGU NONEGU ONROAD NONROAD AREA FIRES YEAR 

2,295 47,037 127,295 60,487 182,674 25,278 2002 Actual 

2,288 47,035 127,295 60,487 182,674 26,526 2002 Typical 

AL 2,473 46,644 76,990 50,249 143,454 27,502 2009 

2,952 54,291 49,175 40,407 153,577 27,539 2018 

2,524 38,471 527,209 272,072 404,302 42,724 2002 Actual 

2,531 38,471 527,209 272,072 404,302 51,527 2002 Typical 

FL 2,730 36,882 340,947 209,543 420,172 51,527 2009 

3,047 42,813 222,303 183,452 489,975 51,527 2018 

1,244 33,709 283,421 85,965 299,679 33,979 2002 Actual 

1,256 33,709 283,421 85,965 299,679 33,918 2002 Typical 

GA 2,314 34,116 195,125 67,686 272,315 34,710 2009 

2,816 40,282 109,763 56,761 319,328 34,710 2018 

1,487 44,834 103,503 44,805 95,375 410 2002 Actual 

1,481 44,834 103,503 44,805 95,375 1,172 2002 Typical 

KY 1,369 47,786 73,942 38,558 94,042 1,497 2009 

1,426 55,861 47,066 30,920 103,490 1,567 2018 

648 43,204 87,672 41,081 131,808 622 2002 Actual 

629 43,203 87,672 41,081 131,808 675 2002 Typical 

MS 564 37,747 52,107 36,197 124,977 2,266 2009 

1,274 45,335 31,616 28,842 140,134 2,355 2018 

988 61,182 263,766 94,480 237,926 1,624 2002 Actual 

986 61,182 263,766 94,480 237,926 3,387 2002 Typical 

NC 954 61,925 168,676 74,056 187,769 4,530 2009 

1,302 70,875 101,099 61,327 189,591 5,236 2018 

470 38,458 116,163 55,016 161,000 14,202 2002 Actual 

470 38,458 116,163 55,016 161,000 14,666 2002 Typical 

SC 723 34,403 72,603 43,061 146,107 16,045 2009 

931 41,987 46,301 36,131 161,228 16,045 2018 

926 84,328 179,807 66,450 153,307 202 2002 Actual 

890 84,328 179,807 66,450 153,307 476 2002 Typical 

TN 932 73,498 115,181 55,358 154,377 817 2009 

976 92,456 67,324 45,084 182,222 888 2018 

754 43,152 159,790 74,866 174,116 735 2002 Actual 

747 43,152 159,790 74,866 174,116 593 2002 Typical 

VA 788 43,726 96,770 57,009 147,034 994 2009 

980 53,186 61,964 49,052 150,919 1,267 2018 

1,180 14,595 42,174 18,566 60,443 317 2002 Actual 

1,140 14,595 42,174 18,566 60,443 125 2002 Typical 

WV 1,361 13,043 24,843 18,069 55,288 186 2009 

1,387 15,582 16,121 14,086 60,747 236 2018 
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Appendix B MACTEC, Inc. 213

APPENDIX B: 

STATE VMT TOTALS 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories 

Appendix B MACTEC, Inc. 214

State VMT Totals 

Million Miles Per Year 

2002 LDGV LDGT1 LDGT2 HDDV LDDV LDDT HDDV MC TOTAL 

AL 31,982 12,728 4,347 1,630 63 69 4,709 196 55,723 

FL 105,340 40,835 13,945 5,079 206 220 12,465 591 178,681 

GA 61,660 24,394 8,331 3,103 121 132 8,673 371 106,785 

KY 28,751 12,189 3,366 1,606 55 55 4,827 171 51,020 

MS 23,933 6,724 439 1,025 330 125 3,610 92 36,278 

NC 51,189 30,339 10,787 4,119 230 230 9,440 461 106,795 

SC 26,672 10,750 3,671 1,395 52 58 4,306 171 47,074 

TN 30,809 20,272 6,922 2,943 52 111 6,810 397 68,316 

VA 36,336 24,784 8,667 2,148 61 139 4,969 369 77,472 

WV 9,010 5,931 2,028 732 25 37 1,664 117 19,544 

 

2009 LDGV LDGT1 LDGT2 HDDV LDDV LDDT HDDV MC TOTAL 

AL 30,638 18,598 5,511 2,069 65 72 5,976 249 63,178 

FL 107,641 62,449 18,697 6,820 215 230 16,743 794 213,590 

GA 61,569 36,641 10,933 4,077 126 137 11,374 487 125,343 

KY 28,006 16,984 4,428 1,983 58 57 5,983 231 57,729 

MS 23,641 10,131 573 1,341 356 135 4,719 120 41,017 

NC 48,495 43,484 15,122 4,576 40 224 10,928 527 123,396 

SC 26,451 16,119 4,796 1,824 55 61 5,617 223 55,147 

TN 28,775 28,650 8,521 3,627 52 111 8,391 490 78,615 

VA 33,663 34,814 10,597 2,624 61 137 6,073 451 88,419 

WV 8,128 8,205 2,427 878 25 37 1,995 140 21,835 

 

2018 LDGV LDGT1 LDGT2 HDDV LDDV LDDT HDDV MC TOTAL 

AL 31,706 23,562 6,990 2,634 67 84 7,607 317 72,966 

FL 116,576 83,385 24,996 9,156 221 301 22,491 1,066 258,191 

GA 65,214 47,687 14,245 5,332 129 171 14,853 637 148,269 

KY 29,353 21,058 5,558 2,463 60 66 7,454 288 66,300 

MS 24,787 12,984 736 1,727 372 159 6,076 155 46,996 

NC 42,247 51,568 18,260 4,985 279 279 11,396 553 129,566 

SC 27,930 20,880 6,220 2,375 57 75 7,306 290 65,133 

TN 29,253 35,702 10,629 4,538 52 130 10,500 613 91,417 

VA 35,030 44,438 13,543 3,358 62 164 7,770 578 104,944 

WV 8,130 10,025 2,969 1,078 25 41 2,451 172 24,891 
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Appendix C MACTEC, Inc. 215

APPENDIX C: 

STATE TIER 1 EMISSION TOTALS 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories 

Appendix C MACTEC, Inc. 216

State Tier 1 Emission Totals 

State Year TIER1 TIER 1 NAME CO NH3 NOX PM10 PM2.5 SO2 VOC 

AL 2002 01 FUEL COMB. ELEC. UTIL. 11,279 317 161,038 7,646 4,113 447,828 2,295 

AL 2002 02 FUEL COMB. INDUSTRIAL 67,132 234 51,535 6,730 3,792 40,918 2,239 

AL 2002 03 FUEL COMB. OTHER 70,498 169 19,237 6,411 5,528 39,606 56,120 

AL 2002 04 CHEMICAL & ALLIED PRODUCT 

MFG 5,721 35 2,032 1,220 888 12,770 7,273 

AL 2002 05 METALS PROCESSING 38,247 376 6,011 9,107 7,803 14,039 3,299 

AL 2002 06 PETROLEUM & RELATED 

INDUSTRIES 13,606 0 878 194 155 22,991 4,024 

AL 2002 07 OTHER INDUSTRIAL PROCESSES 47,676 1,468 25,252 22,689 9,516 17,904 25,304 

AL 2002 08 SOLVENT UTILIZATION 216 0 226 149 126 3 108,437 

AL 2002 09 STORAGE & TRANSPORT 174 0 230 1,086 636 13 16,522 

AL 2002 10 WASTE DISPOSAL & RECYCLING 104,914 10 4,016 15,832 14,946 489 12,612 

AL 2002 11 HIGHWAY VEHICLES 1,321,528 5,588 158,212 3,903 2,799 6,900 127,295 

AL 2002 12 OFF-HIGHWAY 414,385 33 65,366 4,787 4,502 7,584 60,487 

AL 2002 14 MISCELLANEOUS 385,005 59,596 8,065 402,646 74,483 2,208 19,161 

 2002 

Total 2,480,381 67,827 502,098 482,402 129,287 613,255 445,065 

AL 2009 01 FUEL COMB. ELEC. UTIL. 14,986 359 82,305 6,969 3,921 378,052 2,473 

AL 2009 02 FUEL COMB. INDUSTRIAL 68,146 274 36,301 6,140 3,438 40,651 2,191 

AL 2009 03 FUEL COMB. OTHER 52,256 158 19,514 5,904 5,104 36,048 31,403 

AL 2009 04 CHEMICAL & ALLIED PRODUCT 

MFG 6,118 38 2,273 1,257 912 13,660 6,613 

AL 2009 05 METALS PROCESSING 38,969 500 6,021 9,062 7,756 16,629 3,305 

AL 2009 06 PETROLEUM & RELATED 

INDUSTRIES 13,241 0 858 221 177 22,495 3,336 

AL 2009 07 OTHER INDUSTRIAL PROCESSES 52,004 1,571 26,340 24,196 10,197 19,383 26,519 

AL 2009 08 SOLVENT UTILIZATION 247 0 257 165 139 4 92,631 

AL 2009 09 STORAGE & TRANSPORT 192 0 253 1,146 584 14 17,738 

AL 2009 10 WASTE DISPOSAL & RECYCLING 87,225 11 3,634 14,504 13,485 590 11,207 

AL 2009 11 HIGHWAY VEHICLES 915,647 6,364 101,831 3,171 2,032 810 76,990 

AL 2009 12 OFF-HIGHWAY 454,686 36 56,862 4,027 3,776 3,471 50,249 

AL 2009 14 MISCELLANEOUS 463,498 65,899 9,788 428,698 82,679 2,681 22,657 

 2009 

Total 2,167,216 75,209 346,238 505,457 134,201 534,489 347,312 

AL 2018 01 FUEL COMB. ELEC. UTIL. 24,342 1,072 64,358 7,822 4,768 135,851 2,952 

AL 2018 02 FUEL COMB. INDUSTRIAL 69,068 275 38,424 6,427 3,599 40,126 2,293 

AL 2018 03 FUEL COMB. OTHER 43,744 164 20,185 5,641 4,818 37,162 21,215 

AL 2018 04 CHEMICAL & ALLIED PRODUCT 

MFG 7,384 46 2,804 1,523 1,106 16,509 8,040 

AL 2018 05 METALS PROCESSING 49,770 674 7,519 11,036 9,423 21,824 4,234 

AL 2018 06 PETROLEUM & RELATED 

INDUSTRIES 13,002 0 848 258 207 15,364 3,421 

AL 2018 07 OTHER INDUSTRIAL PROCESSES 60,452 1,732 30,831 27,727 11,812 21,843 30,267 

AL 2018 08 SOLVENT UTILIZATION 301 0 317 200 169 4 112,412 

AL 2018 09 STORAGE & TRANSPORT 234 0 307 1,366 699 17 18,900 

AL 2018 10 WASTE DISPOSAL & RECYCLING 88,758 13 3,867 15,343 14,143 718 11,938 

AL 2018 11 HIGHWAY VEHICLES 676,210 7,298 47,298 2,410 1,192 720 49,175 

AL 2018 12 OFF-HIGHWAY 488,924 42 43,799 3,041 2,835 2,818 40,407 

AL 2018 14 MISCELLANEOUS 464,235 73,529 9,803 458,551 85,538 2,686 22,686 

 2018 

Total 1,986,424 84,845 270,362 541,346 140,310 295,642 327,940 
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Appendix C MACTEC, Inc. 217

State Tier 1 Emission Totals 

State Year TIER1 TIER 1 NAME CO NH3 NOX PM10 PM2.5 SO2 VOC 

FL 2002 01 FUEL COMB. ELEC. UTIL. 57,113 234 257,677 21,387 15,643 453,631 2,524 

FL 2002 02 FUEL COMB. INDUSTRIAL 64,798 131 45,157 20,442 18,547 42,524 4,219 

FL 2002 03 FUEL COMB. OTHER 49,230 99 11,597 8,464 8,074 20,031 16,123 

FL 2002 04 CHEMICAL & ALLIED 

PRODUCT MFG 745 1,101 2,221 1,868 1,488 34,462 3,542 

FL 2002 05 METALS PROCESSING 1,404 1 194 449 334 882 82 

FL 2002 06 PETROLEUM & RELATED 

INDUSTRIES 1,070 0 560 259 129 470 724 

FL 2002 07 OTHER INDUSTRIAL 

PROCESSES 18,586 19 12,325 23,419 11,844 6,515 27,024 

FL 2002 08 SOLVENT UTILIZATION 0 0 1 128 110 0 304,582 

FL 2002 09 STORAGE & TRANSPORT 161 0 561 1,645 720 38 79,281 

FL 2002 10 WASTE DISPOSAL & 

RECYCLING 54,721 351 2,535 9,943 9,405 659 9,125 

FL 2002 11 HIGHWAY VEHICLES 4,550,447 18,114 465,640 11,275 7,868 20,915 527,209 

FL 2002 12 OFF-HIGHWAY 1,920,729 134 180,627 18,281 17,415 20,614 272,072 

FL 2002 14 MISCELLANEOUS 752,915 40,269 14,821 497,846 114,447 4,057 40,795 

 2002 

Total 7,471,920 60,454 993,915 615,407 206,025 604,797 1,287,301 

FL 2009 01 FUEL COMB. ELEC. UTIL. 35,928 1,631 86,165 9,007 5,910 186,055 1,910 

FL 2009 02 FUEL COMB. INDUSTRIAL 69,972 146 44,480 16,265 14,827 38,225 4,473 

FL 2009 03 FUEL COMB. OTHER 33,014 100 10,800 7,555 7,174 19,882 10,907 

FL 2009 04 CHEMICAL & ALLIED 

PRODUCT MFG 901 1,231 2,461 1,908 1,526 34,961 3,821 

FL 2009 05 METALS PROCESSING 1,545 1 176 361 251 993 82 

FL 2009 06 PETROLEUM & RELATED 

INDUSTRIES 1,190 0 612 304 156 519 748 

FL 2009 07 OTHER INDUSTRIAL 

PROCESSES 18,593 26 13,521 33,084 19,357 6,881 26,413 

FL 2009 08 SOLVENT UTILIZATION 0 0 1 132 113 0 319,723 

FL 2009 09 STORAGE & TRANSPORT 187 0 621 1,661 727 50 83,880 

FL 2009 10 WASTE DISPOSAL & 

RECYCLING 177,953 342 6,251 22,971 22,364 698 17,241 

FL 2009 11 HIGHWAY VEHICLES 3,308,863 21,549 312,321 9,801 6,104 2,584 336,707 

FL 2009 12 OFF-HIGHWAY 2,104,920 148 163,794 15,613 14,866 8,967 209,543 

FL 2009 14 MISCELLANEOUS 764,004 41,471 15,075 557,331 120,796 4,129 41,290 

 2009 

Total 6,596,484 66,874 707,273 687,353 223,192 406,888 1,061,801 

FL 2018 01 FUEL COMB. ELEC. UTIL. 85,495 2,976 87,645 12,791 9,417 194,028 3,047 

FL 2018 02 FUEL COMB. INDUSTRIAL 77,465 156 48,879 17,876 16,324 37,205 4,894 

FL 2018 03 FUEL COMB. OTHER 27,094 110 12,356 7,255 6,853 20,975 8,879 

FL 2018 04 CHEMICAL & ALLIED 

PRODUCT MFG 1,200 1,448 3,119 2,367 1,907 41,395 4,739 

FL 2018 05 METALS PROCESSING 1,973 2 225 466 323 1,325 106 

FL 2018 06 PETROLEUM & RELATED 

INDUSTRIES 1,513 0 778 387 198 659 918 

FL 2018 07 OTHER INDUSTRIAL 

PROCESSES 20,748 35 15,855 39,842 23,289 7,741 29,716 

FL 2018 08 SOLVENT UTILIZATION 0 0 1 158 135 0 387,657 

FL 2018 09 STORAGE & TRANSPORT 226 0 690 2,004 877 58 87,732 

FL 2018 10 WASTE DISPOSAL & 

RECYCLING 180,730 418 6,486 24,140 23,427 769 18,335 

FL 2018 11 HIGHWAY VEHICLES 2,554,160 26,163 150,180 8,268 4,038 2,533 222,303 

FL 2018 12 OFF-HIGHWAY 2,323,327 171 127,885 12,497 11,868 7,536 183,452 

FL 2018 14 MISCELLANEOUS 763,701 43,251 15,068 628,984 127,364 4,129 41,338 

 2018 

Total 6,037,633 74,728 469,168 757,033 226,019 318,353 993,116 
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Appendix C MACTEC, Inc. 218

State Tier 1 Emission Totals 

State Year TIER1 TIER 1 NAME CO NH3 NOX PM10 PM2.5 SO2 VOC 

GA 2002 01 FUEL COMB. ELEC. UTIL. 9,712 83 147,517 11,224 4,939 514,952 1,244 

GA 2002 02 FUEL COMB. INDUSTRIAL 59,492 27 53,039 12,037 7,886 88,791 3,956 

GA 2002 03 FUEL COMB. OTHER 63,314 17 14,465 10,142 10,057 10,740 27,226 

GA 2002 04 CHEMICAL & ALLIED PRODUCT MFG 5,387 920 2,277 391 305 2,721 2,668 

GA 2002 05 METALS PROCESSING 330 0 60 147 94 0 70 

GA 2002 06 PETROLEUM & RELATED INDUSTRIES 41 0 3 69 44 68 175 

GA 2002 07 OTHER INDUSTRIAL PROCESSES 27,960 2,666 12,215 39,630 13,073 8,701 26,999 

GA 2002 08 SOLVENT UTILIZATION 4 0 22 13 13 0 234,744 

GA 2002 09 STORAGE & TRANSPORT 39 0 6 583 360 0 26,334 

GA 2002 10 WASTE DISPOSAL & RECYCLING 146,183 16 5,164 23,422 22,506 312 15,003 

GA 2002 11 HIGHWAY VEHICLES 2,735,968 10,546 307,732 7,246 5,168 12,184 283,421 

GA 2002 12 OFF-HIGHWAY 791,158 60 97,961 8,618 8,226 9,005 85,965 

GA 2002 14 MISCELLANEOUS 590,400 83,458 12,308 695,723 124,142 3,372 29,640 

 2002 

Total 4,429,989 97,795 652,769 809,244 196,815 650,846 737,444 

GA 2009 01 FUEL COMB. ELEC. UTIL. 23,721 686 98,497 17,891 10,907 408,679 2,314 

GA 2009 02 FUEL COMB. INDUSTRIAL 63,067 28 53,726 11,206 7,390 89,850 4,163 

GA 2009 03 FUEL COMB. OTHER 45,184 17 15,347 8,496 8,400 10,981 15,683 

GA 2009 04 CHEMICAL & ALLIED PRODUCT MFG 6,044 1,032 2,531 436 341 2,743 2,814 

GA 2009 05 METALS PROCESSING 363 0 61 159 100 0 47 

GA 2009 06 PETROLEUM & RELATED INDUSTRIES 50 0 4 83 54 82 154 

GA 2009 07 OTHER INDUSTRIAL PROCESSES 29,976 2,902 12,528 45,339 14,758 7,662 28,441 

GA 2009 08 SOLVENT UTILIZATION 4 0 25 14 14 0 216,248 

GA 2009 09 STORAGE & TRANSPORT 45 0 7 649 401 0 27,821 

GA 2009 10 WASTE DISPOSAL & RECYCLING 218,460 18 7,419 31,955 30,900 360 18,711 

GA 2009 11 HIGHWAY VEHICLES 1,983,803 12,687 209,349 6,072 3,840 1,585 195,125 

GA 2009 12 OFF-HIGHWAY 882,970 68 85,733 7,521 7,175 2,725 67,686 

GA 2009 14 MISCELLANEOUS 515,329 91,406 10,637 765,043 125,665 2,914 26,388 

 2009 

Total 3,769,016 108,844 495,864 894,865 209,944 527,582 605,595 

GA 2018 01 FUEL COMB. ELEC. UTIL. 44,269 1,677 69,856 20,732 13,881 68,515 2,816 

GA 2018 02 FUEL COMB. INDUSTRIAL 67,067 30 57,232 11,755 7,769 94,403 4,424 

GA 2018 03 FUEL COMB. OTHER 39,440 17 17,801 7,722 7,622 11,958 11,482 

GA 2018 04 CHEMICAL & ALLIED PRODUCT MFG 7,076 1,208 2,982 517 405 3,436 3,524 

GA 2018 05 METALS PROCESSING 421 0 76 185 118 0 55 

GA 2018 06 PETROLEUM & RELATED INDUSTRIES 63 0 5 105 68 104 191 

GA 2018 07 OTHER INDUSTRIAL PROCESSES 33,611 3,559 14,460 55,130 17,899 8,748 33,333 

GA 2018 08 SOLVENT UTILIZATION 5 0 30 22 22 0 264,326 

GA 2018 09 STORAGE & TRANSPORT 54 0 9 764 470 0 29,409 

GA 2018 10 WASTE DISPOSAL & RECYCLING 235,690 22 8,120 35,280 34,038 423 20,411 

GA 2018 11 HIGHWAY VEHICLES 1,476,981 14,873 102,179 4,844 2,380 1,457 109,763 

GA 2018 12 OFF-HIGHWAY 973,872 79 64,579 6,015 5,730 1,709 56,761 

GA 2018 14 MISCELLANEOUS 515,220 102,075 10,635 859,835 134,730 2,914 26,368 

 2018 

Total 3,393,769 123,540 347,964 1,002,907 225,133 193,668 562,862 
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Appendix C MACTEC, Inc. 220

State Tier 1 Emission Totals 

State Year TIER1 TIER 1 NAME CO NH3 NOX PM10 PM2.5 SO2 VOC 

KY 2002 01 FUEL COMB. ELEC. UTIL. 12,619 326 198,817 4,701 2,802 484,057 1,487 

KY 2002 02 FUEL COMB. INDUSTRIAL 14,110 182 60,674 2,155 1,463 41,825 1,565 

KY 2002 03 FUEL COMB. OTHER 40,806 55 4,997 7,679 7,352 9,647 12,711 

KY 2002 04 CHEMICAL & ALLIED PRODUCT MFG 176 214 296 774 581 2,345 3,462 

KY 2002 05 METALS PROCESSING 89,197 6 1,082 3,396 2,720 12,328 1,508 

KY 2002 06 PETROLEUM & RELATED 

INDUSTRIES 4,304 335 2,519 308 205 5,747 2,895 

KY 2002 07 OTHER INDUSTRIAL PROCESSES 6,493 78 6,518 31,429 10,394 3,333 25,388 

KY 2002 08 SOLVENT UTILIZATION 0 10 9 317 241 1 61,834 

KY 2002 09 STORAGE & TRANSPORT 33 8 15 1,920 1,177 3 18,853 

KY 2002 10 WASTE DISPOSAL & RECYCLING 20,622 8 1,768 7,229 6,476 606 7,927 

KY 2002 11 HIGHWAY VEHICLES 1,230,148 5,055 156,417 3,723 2,697 6,308 103,503 

KY 2002 12 OFF-HIGHWAY 325,993 31 104,571 6,425 6,046 14,043 44,805 

KY 2002 14 MISCELLANEOUS 9,651 50,953 209 195,827 26,941 51 4,476 

 2002 

Total 1,754,151 57,261 537,890 265,880 69,094 580,293 290,414 

KY 2009 01 FUEL COMB. ELEC. UTIL. 15,812 400 97,263 6,463 4,279 271,669 1,369 

KY 2009 02 FUEL COMB. INDUSTRIAL 14,986 195 61,683 2,105 1,456 42,433 1,476 

KY 2009 03 FUEL COMB. OTHER 30,045 54 5,178 7,035 6,725 10,123 9,148 

KY 2009 04 CHEMICAL & ALLIED PRODUCT MFG 179 249 300 851 633 2,384 3,635 

KY 2009 05 METALS PROCESSING 99,428 7 1,156 3,246 2,550 13,735 1,772 

KY 2009 06 PETROLEUM & RELATED 

INDUSTRIES 4,818 377 2,828 344 230 6,460 3,052 

KY 2009 07 OTHER INDUSTRIAL PROCESSES 7,212 84 6,674 32,194 10,912 3,634 27,548 

KY 2009 08 SOLVENT UTILIZATION 0 10 11 371 283 1 62,595 

KY 2009 09 STORAGE & TRANSPORT 38 9 18 2,064 1,268 3 20,038 

KY 2009 10 WASTE DISPOSAL & RECYCLING 22,388 9 1,979 7,770 6,925 733 7,725 

KY 2009 11 HIGHWAY VEHICLES 963,762 5,796 101,182 2,976 1,920 759 73,942 

KY 2009 12 OFF-HIGHWAY 357,800 34 94,752 5,544 5,203 9,180 38,558 

KY 2009 14 MISCELLANEOUS 32,627 52,915 702 206,463 29,601 187 6,335 

 2009 

Total 1,549,096 60,139 373,725 277,427 71,984 361,300 257,193 

KY 2018 01 FUEL COMB. ELEC. UTIL. 17,144 476 64,378 6,694 4,434 222,102 1,426 

KY 2018 02 FUEL COMB. INDUSTRIAL 15,692 205 64,533 2,203 1,528 43,772 1,555 

KY 2018 03 FUEL COMB. OTHER 24,764 53 5,550 6,469 6,169 9,947 7,479 

KY 2018 04 CHEMICAL & ALLIED PRODUCT MFG 219 317 367 1,054 781 2,884 4,384 

KY 2018 05 METALS PROCESSING 114,470 9 1,508 3,898 3,065 15,800 2,343 

KY 2018 06 PETROLEUM & RELATED 

INDUSTRIES 5,495 434 3,244 392 262 7,426 3,394 

KY 2018 07 OTHER INDUSTRIAL PROCESSES 8,303 93 7,872 35,349 12,377 4,141 31,394 

KY 2018 08 SOLVENT UTILIZATION 0 12 14 464 352 1 73,525 

KY 2018 09 STORAGE & TRANSPORT 44 10 21 2,408 1,481 4 21,196 

KY 2018 10 WASTE DISPOSAL & RECYCLING 24,677 11 2,256 8,481 7,518 894 8,392 

KY 2018 11 HIGHWAY VEHICLES 807,536 7,811 52,263 2,580 1,272 763 47,066 

KY 2018 12 OFF-HIGHWAY 381,215 40 79,392 4,556 4,256 8,592 30,920 

KY 2018 14 MISCELLANEOUS 33,931 55,118 729 218,725 30,626 196 7,254 

 2018 

Total 1,433,491 64,588 282,127 293,273 74,122 316,520 240,329 
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Appendix C MACTEC, Inc. 221

State Tier 1 Emission Totals 

State Year TIER1 TIER 1 NAME CO NH3 NOX PM10 PM2.5 SO2 VOC 

MS 2002 01 FUEL COMB. ELEC. UTIL. 5,303 190 43,135 1,633 1,138 67,429 648 

MS 2002 02 FUEL COMB. INDUSTRIAL 22,711 28 48,699 5,011 3,638 9,746 8,024 

MS 2002 03 FUEL COMB. OTHER 36,752 34 4,502 5,445 5,414 789 22,923 

MS 2002 04 CHEMICAL & ALLIED PRODUCT MFG 15,410 361 1,725 849 440 1,663 2,375 

MS 2002 05 METALS PROCESSING 1,031 0 115 122 58 36 371 

MS 2002 06 PETROLEUM & RELATED 

INDUSTRIES 975 20 1,187 790 335 15,560 20,788 

MS 2002 07 OTHER INDUSTRIAL PROCESSES 13,884 747 9,219 27,617 8,051 8,866 15,525 

MS 2002 08 SOLVENT UTILIZATION 45 7 105 219 178 1 80,760 

MS 2002 09 STORAGE & TRANSPORT 74 0 80 124 38 40 23,327 

MS 2002 10 WASTE DISPOSAL & RECYCLING 1,414 9 89 447 324 31 886 

MS 2002 11 HIGHWAY VEHICLES 864,290 3,585 111,914 2,859 2,112 4,614 87,672 

MS 2002 12 OFF-HIGHWAY 236,752 23 88,787 5,010 4,690 11,315 41,081 

MS 2002 14 MISCELLANEOUS 13,386 58,741 288 323,511 42,932 78 654 

 2002 

Total 1,212,028 63,748 309,845 373,637 69,348 120,166 305,035 

MS 2009 01 FUEL COMB. ELEC. UTIL. 7,116 334 47,276 5,182 4,996 76,646 564 

MS 2009 02 FUEL COMB. INDUSTRIAL 24,607 30 44,095 3,728 2,787 7,388 8,007 

MS 2009 03 FUEL COMB. OTHER 26,024 33 4,514 5,278 5,245 751 17,445 

MS 2009 04 CHEMICAL & ALLIED PRODUCT MFG 16,141 405 1,955 941 488 1,880 2,614 

MS 2009 05 METALS PROCESSING 1,098 0 128 129 62 37 402 

MS 2009 06 PETROLEUM & RELATED 

INDUSTRIES 1,101 23 1,262 894 379 7,926 13,317 

MS 2009 07 OTHER INDUSTRIAL PROCESSES 14,181 197 8,376 31,380 8,628 8,254 16,282 

MS 2009 08 SOLVENT UTILIZATION 50 8 118 239 194 1 80,393 

MS 2009 09 STORAGE & TRANSPORT 92 0 100 172 59 49 23,494 

MS 2009 10 WASTE DISPOSAL & RECYCLING 1,486 10 95 473 339 32 743 

MS 2009 11 HIGHWAY VEHICLES 609,972 4,035 70,743 2,275 1,508 537 52,107 

MS 2009 12 OFF-HIGHWAY 257,453 25 80,567 4,270 3,985 7,191 36,197 

MS 2009 14 MISCELLANEOUS 48,314 63,886 1,037 337,018 46,695 283 2,295 

 2009 

Total 1,007,634 68,987 260,266 391,978 75,365 110,975 253,858 

MS 2018 01 FUEL COMB. ELEC. UTIL. 17,348 827 21,535 7,412 7,252 15,213 1,274 

MS 2018 02 FUEL COMB. INDUSTRIAL 26,082 33 46,792 4,073 3,039 5,167 8,556 

MS 2018 03 FUEL COMB. OTHER 20,900 32 4,768 4,964 4,928 726 14,670 

MS 2018 04 CHEMICAL & ALLIED PRODUCT MFG 20,175 475 2,337 1,132 588 2,242 3,290 

MS 2018 05 METALS PROCESSING 1,357 0 167 160 79 48 461 

MS 2018 06 PETROLEUM & RELATED 

INDUSTRIES 1,267 26 1,294 1,010 430 8,484 14,407 

MS 2018 07 OTHER INDUSTRIAL PROCESSES 16,267 216 9,996 38,492 10,492 9,657 20,301 

MS 2018 08 SOLVENT UTILIZATION 60 9 141 301 244 1 98,354 

MS 2018 09 STORAGE & TRANSPORT 115 0 124 210 73 62 24,537 

MS 2018 10 WASTE DISPOSAL & RECYCLING 1,638 12 114 533 372 34 870 

MS 2018 11 HIGHWAY VEHICLES 445,493 4,566 30,619 1,624 819 440 31,616 

MS 2018 12 OFF-HIGHWAY 270,726 29 68,252 3,452 3,203 6,638 28,842 

MS 2018 14 MISCELLANEOUS 50,160 70,096 1,076 352,321 47,869 294 2,377 

 2018 

Total 871,587 76,321 187,215 415,685 79,388 49,006 249,556 
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Appendix C MACTEC, Inc. 222

State Tier 1 Emission Totals 

State Year TIER1 TIER 1 NAME CO NH3 NOX PM10 PM2.5 SO2 VOC 

NC 2002 01 FUEL COMB. ELEC. UTIL. 13,885 54 151,850 22,754 16,498 477,990 988 

NC 2002 02 FUEL COMB. INDUSTRIAL 23,578 301 48,590 5,596 4,334 33,395 2,540 

NC 2002 03 FUEL COMB. OTHER 217,008 2,318 16,460 31,777 26,746 3,971 87,985 

NC 2002 04 CHEMICAL & ALLIED PRODUCT MFG 13,952 535 859 866 538 5,736 4,313 

NC 2002 05 METALS PROCESSING 5,876 60 201 564 467 1,010 2,512 

NC 2002 06 PETROLEUM & RELATED 

INDUSTRIES 461 0 174 104 52 283 140 

NC 2002 07 OTHER INDUSTRIAL PROCESSES 8,552 480 7,380 25,328 8,924 3,426 18,025 

NC 2002 08 SOLVENT UTILIZATION 130 307 229 524 484 26 151,383 

NC 2002 09 STORAGE & TRANSPORT 66 46 53 639 354 1 16,120 

NC 2002 10 WASTE DISPOSAL & RECYCLING 125,528 247 7,482 2,239 2,218 1,666 15,568 

NC 2002 11 HIGHWAY VEHICLES 2,873,992 9,702 327,329 6,579 4,623 12,420 263,766 

NC 2002 12 OFF-HIGHWAY 808,231 65 84,284 7,348 7,005 7,693 94,480 

NC 2002 14 MISCELLANEOUS 35,218 158,900 757 229,909 33,291 203 1,765 

 2002 

Total 4,126,478 173,014 645,648 334,226 105,533 547,821 659,585 

NC 2009 01 FUEL COMB. ELEC. UTIL. 14,942 445 66,516 22,152 15,949 242,286 954 

NC 2009 02 FUEL COMB. INDUSTRIAL 24,871 312 38,161 5,159 3,871 30,788 2,510 

NC 2009 03 FUEL COMB. OTHER 158,837 2,723 18,441 25,334 19,467 4,060 49,819 

NC 2009 04 CHEMICAL & ALLIED PRODUCT MFG 14,732 599 933 981 607 6,286 4,925 

NC 2009 05 METALS PROCESSING 6,358 67 207 627 528 1,130 2,790 

NC 2009 06 PETROLEUM & RELATED 

INDUSTRIES 556 0 212 127 64 349 162 

NC 2009 07 OTHER INDUSTRIAL PROCESSES 9,211 507 8,061 28,524 9,788 3,712 18,144 

NC 2009 08 SOLVENT UTILIZATION 142 335 246 549 506 28 136,114 

NC 2009 09 STORAGE & TRANSPORT 75 51 55 696 380 1 17,367 

NC 2009 10 WASTE DISPOSAL & RECYCLING 139,518 307 8,354 2,774 2,750 1,913 17,331 

NC 2009 11 HIGHWAY VEHICLES 1,991,708 11,825 201,609 5,572 3,493 1,503 168,676 

NC 2009 12 OFF-HIGHWAY 887,605 72 70,997 6,055 5,760 1,892 74,056 

NC 2009 14 MISCELLANEOUS 96,825 167,131 2,080 250,912 49,956 566 4,648 

2009 

Total 3,345,380 184,373 415,874 349,461 113,118 294,514 497,496 

NC 2018 01 FUEL COMB. ELEC. UTIL. 19,870 663 61,103 35,275 28,137 120,165 1,302 

NC 2018 02 FUEL COMB. INDUSTRIAL 26,873 341 40,898 5,594 4,222 32,507 2,702 

NC 2018 03 FUEL COMB. OTHER 131,365 2,857 20,027 21,847 16,231 4,050 34,104 

NC 2018 04 CHEMICAL & ALLIED PRODUCT MFG 18,463 702 1,105 1,175 726 7,414 6,113 

NC 2018 05 METALS PROCESSING 7,576 76 255 771 657 1,335 3,516 

NC 2018 06 PETROLEUM & RELATED 

INDUSTRIES 712 0 272 162 82 448 207 

NC 2018 07 OTHER INDUSTRIAL PROCESSES 10,675 559 9,259 34,339 11,601 4,357 20,978 

NC 2018 08 SOLVENT UTILIZATION 169 375 277 588 540 31 152,979 

NC 2018 09 STORAGE & TRANSPORT 91 59 67 808 430 2 19,511 

NC 2018 10 WASTE DISPOSAL & RECYCLING 156,599 387 9,456 3,502 3,474 2,234 19,789 

NC 2018 11 HIGHWAY VEHICLES 1,362,214 14,065 87,791 4,392 2,123 1,481 101,099 

NC 2018 12 OFF-HIGHWAY 960,709 83 49,046 4,298 4,069 905 61,327 

NC 2018 14 MISCELLANEOUS 111,705 177,474 2,399 273,030 54,376 655 5,333 

 2018 

Total 2,807,022 197,643 281,955 385,780 126,667 175,583 428,960 
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Appendix C MACTEC, Inc. 223

State Tier 1 Emission Totals 

State Year TIER1 TIER 1 NAME CO NH3 NOX PM10 PM2.5 SO2 VOC 

SC 2002 01 FUEL COMB. ELEC. UTIL. 6,990 142 88,241 21,400 17,154 206,399 470 

SC 2002 02 FUEL COMB. INDUSTRIAL 31,771 97 38,081 5,308 3,641 44,958 1,338 

SC 2002 03 FUEL COMB. OTHER 75,800 65 4,367 6,261 6,166 4,318 49,171 

SC 2002 04 CHEMICAL & ALLIED PRODUCT MFG 2,526 173 25 501 318 59 8,784 

SC 2002 05 METALS PROCESSING 13,833 0 450 639 408 4,160 660 

SC 2002 06 PETROLEUM & RELATED 

INDUSTRIES 248 0 283 120 71 170 114 

SC 2002 07 OTHER INDUSTRIAL PROCESSES 9,502 1,237 15,145 15,224 6,981 12,128 16,342 

SC 2002 08 SOLVENT UTILIZATION 0 1 1 78 60 0 88,878 

SC 2002 09 STORAGE & TRANSPORT 10 0 4 1,025 626 0 21,009 

SC 2002 10 WASTE DISPOSAL & RECYCLING 44,844 10 3,380 6,852 6,321 625 13,708 

SC 2002 11 HIGHWAY VEHICLES 1,241,359 4,694 140,489 3,452 2,501 5,972 116,163 

SC 2002 12 OFF-HIGHWAY 413,964 33 50,249 4,152 3,945 4,866 55,016 

SC 2002 14 MISCELLANEOUS 239,836 28,975 4,678 264,959 48,898 1,281 13,655 

2002 

Total 2,080,683 35,426 345,395 329,971 97,090 284,936 385,308 

SC 2009 01 FUEL COMB. ELEC. UTIL. 11,643 370 48,668 20,041 16,548 129,122 723 

SC 2009 02 FUEL COMB. INDUSTRIAL 32,661 105 35,011 2,978 2,087 36,660 1,374 

SC 2009 03 FUEL COMB. OTHER 49,914 63 4,551 5,264 5,183 4,359 25,073 

SC 2009 04 CHEMICAL & ALLIED PRODUCT MFG 2,798 173 26 543 345 60 7,409 

SC 2009 05 METALS PROCESSING 15,632 0 448 631 378 4,856 663 

SC 2009 06 PETROLEUM & RELATED 

INDUSTRIES 302 0 340 145 86 200 131 

SC 2009 07 OTHER INDUSTRIAL PROCESSES 10,241 1,403 15,069 18,201 7,997 13,443 15,425 

SC 2009 08 SOLVENT UTILIZATION 1 1 1 75 58 0 94,590 

SC 2009 09 STORAGE & TRANSPORT 13 0 5 569 352 0 21,987 

SC 2009 10 WASTE DISPOSAL & RECYCLING 70,379 11 4,215 9,526 8,977 666 15,998 

SC 2009 11 HIGHWAY VEHICLES 889,957 5,523 92,499 2,862 1,855 721 72,603 

SC 2009 12 OFF-HIGHWAY 448,625 36 43,235 3,471 3,294 1,701 43,061 

SC 2009 14 MISCELLANEOUS 250,690 31,416 4,962 282,480 51,151 1,359 13,906 

2009 

Total 1,782,856 39,101 249,028 346,786 98,312 193,147 312,943 

SC 2018 01 FUEL COMB. ELEC. UTIL. 14,975 625 51,751 27,640 23,794 95,377 931 

SC 2018 02 FUEL COMB. INDUSTRIAL 35,532 113 36,645 3,683 2,548 38,548 1,482 

SC 2018 03 FUEL COMB. OTHER 39,627 65 5,135 4,791 4,711 4,469 16,391 

SC 2018 04 CHEMICAL & ALLIED PRODUCT MFG 3,296 212 32 664 423 74 9,107 

SC 2018 05 METALS PROCESSING 18,853 0 585 773 476 5,920 867 

SC 2018 06 PETROLEUM & RELATED 

INDUSTRIES 389 0 438 186 110 258 166 

SC 2018 07 OTHER INDUSTRIAL PROCESSES 12,136 1,566 17,507 20,128 8,981 15,863 18,290 

SC 2018 08 SOLVENT UTILIZATION 1 1 1 93 72 0 119,154 

SC 2018 09 STORAGE & TRANSPORT 16 0 6 1,380 842 0 22,739 

SC 2018 10 WASTE DISPOSAL & RECYCLING 73,403 13 4,512 10,038 9,443 735 17,167 

SC 2018 11 HIGHWAY VEHICLES 663,493 6,473 43,490 2,184 1,087 643 46,301 

SC 2018 12 OFF-HIGHWAY 481,332 41 31,758 2,617 2,474 1,198 36,131 

SC 2018 14 MISCELLANEOUS 250,637 34,345 4,961 306,342 53,367 1,359 13,896 

2018 

Total 1,593,690 43,455 196,820 380,519 108,327 164,444 302,623 
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Appendix C MACTEC, Inc. 224

State Tier 1 Emission Totals 

State Year TIER1 TIER 1 NAME CO NH3 NOX PM10 PM2.5 SO2 VOC 

TN 2002 01 FUEL COMB. ELEC. UTIL. 7,084 204 157,307 14,640 12,166 334,151 926 

TN 2002 02 FUEL COMB. INDUSTRIAL 15,257 6 44,510 8,015 6,649 74,146 2,021 

TN 2002 03 FUEL COMB. OTHER 77,857 25 15,568 7,967 7,549 16,253 18,346 

TN 2002 04 CHEMICAL & ALLIED PRODUCT MFG 36,920 1,518 1,772 3,246 2,201 6,516 24,047 

TN 2002 05 METALS PROCESSING 41,371 14 1,182 7,620 7,030 5,818 6,898 

TN 2002 06 PETROLEUM & RELATED 

INDUSTRIES 543 0 331 314 243 383 1,850 

TN 2002 07 OTHER INDUSTRIAL PROCESSES 9,420 44 11,794 30,484 12,867 5,845 27,336 

TN 2002 08 SOLVENT UTILIZATION 275 1 5,066 2,103 1,818 58 110,872 

TN 2002 09 STORAGE & TRANSPORT 22 24 105 1,249 736 134 21,962 

TN 2002 10 WASTE DISPOSAL & RECYCLING 22,143 31 1,839 7,068 6,469 349 15,505 

TN 2002 11 HIGHWAY VEHICLES 1,917,842 6,625 238,577 5,371 3,949 9,226 179,807 

TN 2002 12 OFF-HIGHWAY 505,163 43 96,827 6,819 6,458 10,441 66,450 

TN 2002 14 MISCELLANEOUS 5,003 34,292 100 179,440 24,708 25 1,978 

 2002 

Total 2,638,901 42,825 574,980 274,337 92,841 463,345 477,997 

TN 2009 01 FUEL COMB. ELEC. UTIL. 7,214 227 66,405 15,608 13,092 255,410 932 

TN 2009 02 FUEL COMB. INDUSTRIAL 15,536 6 37,046 7,157 5,973 63,076 1,773 

TN 2009 03 FUEL COMB. OTHER 61,442 27 14,792 7,134 6,786 16,955 12,781 

TN 2009 04 CHEMICAL & ALLIED PRODUCT MFG 35,440 1,719 1,958 3,369 2,271 1,949 15,492 

TN 2009 05 METALS PROCESSING 45,183 15 1,245 7,337 6,823 6,537 7,671 

TN 2009 06 PETROLEUM & RELATED 

INDUSTRIES 572 0 328 355 276 263 1,401 

TN 2009 07 OTHER INDUSTRIAL PROCESSES 9,911 62 12,635 32,599 13,687 6,240 28,338 

TN 2009 08 SOLVENT UTILIZATION 309 1 5,983 2,431 2,095 65 112,264 

TN 2009 09 STORAGE & TRANSPORT 26 31 12 1,218 733 42 23,686 

TN 2009 10 WASTE DISPOSAL & RECYCLING 23,810 35 1,993 7,618 6,968 393 14,922 

TN 2009 11 HIGHWAY VEHICLES 1,338,016 7,782 151,912 4,206 2,751 1,076 115,181 

TN 2009 12 OFF-HIGHWAY 554,121 48 86,641 5,877 5,557 5,651 55,358 

TN 2009 14 MISCELLANEOUS 17,921 35,200 379 192,464 26,830 102 2,814 

 2009 

Total 2,109,500 45,152 381,331 287,371 93,842 357,760 392,612 

TN 2018 01 FUEL COMB. ELEC. UTIL. 7,723 241 31,715 15,941 13,387 112,672 976 

TN 2018 02 FUEL COMB. INDUSTRIAL 16,702 7 38,028 7,648 6,408 47,982 1,905 

TN 2018 03 FUEL COMB. OTHER 54,486 30 15,502 6,757 6,412 18,091 10,269 

TN 2018 04 CHEMICAL & ALLIED PRODUCT MFG 45,455 2,053 2,424 4,263 2,888 6,563 19,950 

TN 2018 05 METALS PROCESSING 52,834 17 1,589 9,579 8,953 7,790 9,950 

TN 2018 06 PETROLEUM & RELATED 

INDUSTRIES 665 0 378 414 324 309 1,598 

TN 2018 07 OTHER INDUSTRIAL PROCESSES 10,946 88 14,157 38,196 16,242 7,286 35,126 

TN 2018 08 SOLVENT UTILIZATION 380 1 7,675 3,154 2,717 79 140,760 

TN 2018 09 STORAGE & TRANSPORT 33 41 14 1,571 939 49 25,491 

TN 2018 10 WASTE DISPOSAL & RECYCLING 26,712 42 2,326 8,562 7,828 468 17,530 

TN 2018 11 HIGHWAY VEHICLES 976,634 9,021 69,385 3,092 1,544 948 67,324 

TN 2018 12 OFF-HIGHWAY 593,100 55 70,226 4,672 4,403 5,207 45,084 

TN 2018 14 MISCELLANEOUS 19,210 36,213 408 209,058 28,209 111 3,293 

 2018 

Total 1,804,879 47,809 253,828 312,906 100,255 207,555 379,257 
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Appendix C MACTEC, Inc. 225

State Tier 1 Emission Totals 

State Year TIER1 TIER 1 NAME CO NH3 NOX PM10 PM2.5 SO2 VOC 

VA 2002 01 FUEL COMB. ELEC. UTIL. 6,892 127 86,886 3,960 2,606 241,204 754 

VA 2002 02 FUEL COMB. INDUSTRIAL 64,398 100 75,831 18,480 8,453 137,451 5,332 

VA 2002 03 FUEL COMB. OTHER 98,788 13 15,648 11,572 11,236 5,508 54,496 

VA 2002 04 CHEMICAL & ALLIED PRODUCT MFG 321 2,158 8,062 449 393 2,126 1,530 

VA 2002 05 METALS PROCESSING 3,580 0 937 1,575 1,349 5,251 513 

VA 2002 06 PETROLEUM & RELATED 

INDUSTRIES 23,384 0 182 255 153 170 501 

VA 2002 07 OTHER INDUSTRIAL PROCESSES 12,002 726 9,279 33,409 9,795 17,702 13,086 

VA 2002 08 SOLVENT UTILIZATION 0 4 0 225 210 2 111,511 

VA 2002 09 STORAGE & TRANSPORT 16 7 11 745 505 0 26,121 

VA 2002 10 WASTE DISPOSAL & RECYCLING 16,566 109 1,866 3,152 1,277 1,581 4,065 

VA 2002 11 HIGHWAY VEHICLES 2,163,259 7,852 222,374 4,549 3,102 8,294 159,790 

VA 2002 12 OFF-HIGHWAY 660,105 48 63,219 8,728 8,288 8,663 74,866 

VA 2002 14 MISCELLANEOUS 16,238 43,961 350 182,486 22,086 92 848 

2002 

Total 3,065,551 55,105 484,646 269,585 69,453 428,046 453,413 

VA 2009 01 FUEL COMB. ELEC. UTIL. 12,535 694 64,358 5,606 4,165 174,777 788 

VA 2009 02 FUEL COMB. INDUSTRIAL 67,422 105 67,263 18,346 8,345 131,459 5,483 

VA 2009 03 FUEL COMB. OTHER 66,016 10 15,920 10,059 9,741 5,118 28,062 

VA 2009 04 CHEMICAL & ALLIED PRODUCT MFG 286 2,082 7,790 477 413 1,996 1,419 

VA 2009 05 METALS PROCESSING 3,397 0 827 1,563 1,332 4,813 390 

VA 2009 06 PETROLEUM & RELATED 

INDUSTRIES 26,288 0 197 275 169 187 557 

VA 2009 07 OTHER INDUSTRIAL PROCESSES 12,471 733 9,425 33,961 9,984 18,643 13,394 

VA 2009 08 SOLVENT UTILIZATION 0 5 0 248 231 3 110,127 

VA 2009 09 STORAGE & TRANSPORT 17 7 12 797 544 0 26,456 

VA 2009 10 WASTE DISPOSAL & RECYCLING 20,109 119 2,174 3,823 1,515 1,805 4,789 

VA 2009 11 HIGHWAY VEHICLES 1,453,946 9,086 134,232 3,747 2,241 1,079 96,770 

VA 2009 12 OFF-HIGHWAY 726,815 53 54,993 7,510 7,136 1,707 57,009 

VA 2009 14 MISCELLANEOUS 21,582 46,719 464 198,040 23,990 124 1,077 

2009 

Total 2,410,884 59,612 357,655 284,451 69,806 341,710 346,321 

VA 2018 01 FUEL COMB. ELEC. UTIL. 18,850 606 64,344 12,551 10,773 98,988 980 

VA 2018 02 FUEL COMB. INDUSTRIAL 72,065 114 70,132 19,247 8,904 134,790 5,861 

VA 2018 03 FUEL COMB. OTHER 53,171 14 17,852 9,427 9,086 5,230 18,603 

VA 2018 04 CHEMICAL & ALLIED PRODUCT MFG 338 2,462 9,211 579 502 1,297 1,708 

VA 2018 05 METALS PROCESSING 4,034 0 1,017 1,861 1,592 5,374 469 

VA 2018 06 PETROLEUM & RELATED 

INDUSTRIES 30,284 0 228 315 194 217 642 

VA 2018 07 OTHER INDUSTRIAL PROCESSES 14,029 877 10,836 37,553 11,276 18,088 15,636 

VA 2018 08 SOLVENT UTILIZATION 0 6 0 314 293 3 127,953 

VA 2018 09 STORAGE & TRANSPORT 21 8 15 949 648 0 27,357 

VA 2018 10 WASTE DISPOSAL & RECYCLING 24,293 141 2,595 4,694 1,828 2,170 5,821 

VA 2018 11 HIGHWAY VEHICLES 1,075,104 10,624 63,342 3,212 1,543 1,043 61,964 

VA 2018 12 OFF-HIGHWAY 797,683 61 40,393 6,208 5,891 507 49,052 

VA 2018 14 MISCELLANEOUS 27,223 50,279 584 218,141 26,225 158 1,322 

2018 

Total 2,117,096 65,192 280,549 315,051 78,754 267,867 317,368 
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Appendix C MACTEC, Inc. 226

State Tier 1 Emission Totals 

State Year TIER1 TIER 1 NAME CO NH3 NOX PM10 PM2.5 SO2 VOC 

WV 2002 01 FUEL COMB. ELEC. UTIL. 10,341 121 230,977 4,573 2,210 516,084 1,180 

WV 2002 02 FUEL COMB. INDUSTRIAL 8,685 97 33,825 1,583 1,332 37,111 1,097 

WV 2002 03 FUEL COMB. OTHER 29,480 13 15,220 3,814 3,683 3,990 9,275 

WV 2002 04 CHEMICAL & ALLIED PRODUCT MFG 50,835 80 1,627 950 831 9,052 5,755 

WV 2002 05 METALS PROCESSING 28,837 143 1,570 8,749 7,515 5,619 1,393 

WV 2002 06 PETROLEUM & RELATED INDUSTRIES 1 0 1,086 475 475 7,550 2,163 

WV 2002 07 OTHER INDUSTRIAL PROCESSES 2,003 56 5,347 18,751 5,567 2,316 1,803 

WV 2002 08 SOLVENT UTILIZATION 15 0 18 49 44 0 35,989 

WV 2002 09 STORAGE & TRANSPORT 15 0 3 1,952 947 0 12,432 

WV 2002 10 WASTE DISPOSAL & RECYCLING 9,395 8 599 4,153 3,731 100 5,098 

WV 2002 11 HIGHWAY VEHICLES 533,471 1,908 58,999 1,381 995 2,464 42,174 

WV 2002 12 OFF-HIGHWAY 133,113 9 33,239 1,850 1,728 2,112 18,566 

WV 2002 14 MISCELLANEOUS 6,897 9,928 149 93,030 10,799 40 349 

 2002 

Total 813,089 12,364 382,659 141,310 39,857 586,436 137,275 

WV 2009 01 FUEL COMB. ELEC. UTIL. 11,493 330 85,476 5,657 2,940 268,952 1,361 

WV 2009 02 FUEL COMB. INDUSTRIAL 9,529 104 27,109 1,432 1,243 36,964 979 

WV 2009 03 FUEL COMB. OTHER 21,558 13 14,229 3,351 3,216 4,047 6,824 

WV 2009 04 CHEMICAL & ALLIED PRODUCT MFG 58,271 82 1,804 981 858 10,102 5,426 

WV 2009 05 METALS PROCESSING 24,501 116 1,494 2,016 1,507 5,608 831 

WV 2009 06 PETROLEUM & RELATED INDUSTRIES 1 0 1,221 535 535 8,495 2,172 

WV 2009 07 OTHER INDUSTRIAL PROCESSES 2,288 59 4,995 19,240 5,910 2,570 2,064 

WV 2009 08 SOLVENT UTILIZATION 17 0 20 52 47 0 32,199 

WV 2009 09 STORAGE & TRANSPORT 17 0 3 1,756 695 0 12,997 

WV 2009 10 WASTE DISPOSAL & RECYCLING 9,131 8 583 4,036 3,618 97 4,806 

WV 2009 11 HIGHWAY VEHICLES 365,549 2,148 35,635 1,068 684 279 24,843 

WV 2009 12 OFF-HIGHWAY 152,862 11 30,133 1,640 1,528 359 18,069 

WV 2009 14 MISCELLANEOUS 4,116 10,574 89 93,957 11,002 23 219 

 2009 

Total 659,332 13,446 202,791 135,720 33,782 337,495 112,790 

WV 2018 01 FUEL COMB. ELEC. UTIL. 12,397 143 51,474 5,784 3,116 106,199 1,387 

WV 2018 02 FUEL COMB. INDUSTRIAL 10,174 111 28,764 1,505 1,308 38,571 1,048 

WV 2018 03 FUEL COMB. OTHER 18,891 16 17,254 3,160 3,024 4,065 6,270 

WV 2018 04 CHEMICAL & ALLIED PRODUCT MFG 70,252 99 2,183 1,181 1,034 12,196 6,560 

WV 2018 05 METALS PROCESSING 28,563 148 1,929 2,491 1,887 6,735 1,087 

WV 2018 06 PETROLEUM & RELATED INDUSTRIES 1 0 1,407 616 616 9,786 2,338 

WV 2018 07 OTHER INDUSTRIAL PROCESSES 2,756 68 5,949 21,363 6,809 3,101 2,561 

WV 2018 08 SOLVENT UTILIZATION 20 0 24 61 55 0 37,886 

WV 2018 09 STORAGE & TRANSPORT 19 0 4 2,080 824 0 13,394 

WV 2018 10 WASTE DISPOSAL & RECYCLING 9,237 10 592 4,116 3,674 98 5,153 

WV 2018 11 HIGHWAY VEHICLES 274,804 2,497 17,247 819 405 253 16,121 

WV 2018 12 OFF-HIGHWAY 167,424 13 25,710 1,292 1,198 56 14,086 

WV 2018 14 MISCELLANEOUS 5,175 11,453 112 99,667 11,803 29 268 

 2018 

Total 599,712 14,557 152,647 144,134 35,752 181,088 108,159 
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Appendix C MACTEC, Inc. 227

State Tier 1 Emission Totals 

CO NH3 NOX PM10 PM2.5 SO2 VOC 

VISTAS 2002 Total 30,073,168 665,818 5,429,845 3,895,998 1,075,343 4,879,941 5,178,836 

VISTAS 2009 Total 25,397,398 721,736 3,790,044 4,160,870 1,123,548 3,465,859 4,187,921 

VISTAS 2018 Total 22,645,302 792,678 2,722,636 4,548,634 1,194,728 2,169,725 3,910,170 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories 

Appendix D MACTEC, Inc. 228

APPENDIX D: 

VISTAS TIER 1 EMISSION TOTALS 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories 

Appendix D MACTEC, Inc. 229

VISTAS Tier 1 Emission Totals 

Year TIER1 TIER1NAME CO NH3 NOX 

PM10-

PRI 

PM25-

PRI SO2 VOC 

2002 01 FUEL COMB. ELEC. UTIL. 141,217 1,799 1,523,445 113,917 79,269 3,743,723 12,515 

2002 02 FUEL COMB. INDUSTRIAL 371,932 1,204 499,943 85,357 59,735 550,866 32,333 

2002 03 FUEL COMB. OTHER 759,534 2,810 122,062 99,532 91,805 114,852 354,375 

2002 04 CHEMICAL & ALLIED PRODUCT MFG 131,993 7,093 20,896 11,114 7,982 77,450 63,748 

2002 05 METALS PROCESSING 223,705 601 11,801 32,367 27,778 49,143 17,306 

2002 06 PETROLEUM & RELATED INDUSTRIES 44,633 355 7,204 2,887 1,863 53,392 33,374 

2002 07 OTHER INDUSTRIAL PROCESSES 156,077 7,520 114,474 267,980 97,013 86,736 196,831 

2002 08 SOLVENT UTILIZATION 687 331 5,677 3,805 3,284 90 1,288,990 

2002 09 STORAGE & TRANSPORT 610 85 1,069 10,968 6,100 230 261,959 

2002 10 WASTE DISPOSAL & RECYCLING 546,331 801 28,738 80,336 73,673 6,418 99,497 

2002 11 HIGHWAY VEHICLES 19,432,305 73,670 2,187,683 50,338 35,813 89,296 1,890,798 

2002 12 OFF-HIGHWAY 6,209,596 477 865,130 72,019 68,302 96,336 813,788 

2002 14 MISCELLANEOUS 2,054,548 569,073 41,724 3,065,377 522,726 11,407 113,321 

2002 

Total 30,073,168 665,818 5,429,845 3,895,998 1,075,343 4,879,941 5,178,836 

2009 01 FUEL COMB. ELEC. UTIL. 190,535 5,474 789,299 125,750 91,587 2,497,423 14,208 

2009 02 FUEL COMB. INDUSTRIAL 391,422 1,305 445,967 74,588 51,491 514,636 32,431 

2009 03 FUEL COMB. OTHER 544,289 3,198 123,297 85,410 77,042 112,323 207,146 

2009 04 CHEMICAL & ALLIED PRODUCT MFG 140,910 7,611 22,031 11,742 8,394 76,021 54,168 

2009 05 METALS PROCESSING 236,473 705 11,763 25,130 21,288 54,337 17,954 

2009 06 PETROLEUM & RELATED INDUSTRIES 48,118 399 7,863 3,282 2,124 46,975 25,028 

2009 07 OTHER INDUSTRIAL PROCESSES 166,088 7,545 117,625 298,719 111,218 90,420 202,567 

2009 08 SOLVENT UTILIZATION 771 360 6,662 4,274 3,679 100 1,256,884 

2009 09 STORAGE & TRANSPORT 702 98 1,087 10,729 5,743 160 275,462 

2009 10 WASTE DISPOSAL & RECYCLING 770,459 869 36,697 105,449 97,841 7,287 113,473 

2009 11 HIGHWAY VEHICLES 13,864,869 87,027 1,414,834 41,861 26,498 10,962 1,217,185 

2009 12 OFF-HIGHWAY 6,827,857 530 767,707 61,528 58,279 42,845 649,786 

2009 14 MISCELLANEOUS 2,214,906 606,617 45,212 3,312,407 568,364 12,370 121,629 

2009 

Total 25,397,398 721,736 3,790,044 4,160,870 1,123,548 3,465,859 4,187,921 

2018 01 FUEL COMB. ELEC. UTIL. 262,414 9,306 568,158 152,642 118,959 1,169,110 17,090 

2018 02 FUEL COMB. INDUSTRIAL 416,721 1,383 470,326 80,011 55,648 513,072 34,720 

2018 03 FUEL COMB. OTHER 453,482 3,358 136,431 78,032 69,854 116,672 149,363 

2018 04 CHEMICAL & ALLIED PRODUCT MFG 173,857 9,023 26,564 14,454 10,360 94,010 67,414 

2018 05 METALS PROCESSING 279,850 926 14,871 31,221 26,572 66,150 23,089 

2018 06 PETROLEUM & RELATED INDUSTRIES 53,392 460 8,891 3,845 2,490 43,055 27,283 

2018 07 OTHER INDUSTRIAL PROCESSES 189,922 8,793 136,722 348,119 130,778 100,824 237,601 

2018 08 SOLVENT UTILIZATION 936 404 8,480 5,354 4,601 119 1,515,005 

2018 09 STORAGE & TRANSPORT 855 119 1,258 13,540 7,283 192 290,267 

2018 10 WASTE DISPOSAL & RECYCLING 821,737 1,068 40,324 114,690 105,745 8,544 125,406 

2018 11 HIGHWAY VEHICLES 10,312,627 103,394 663,796 33,426 16,403 10,281 752,732 

2018 12 OFF-HIGHWAY 7,438,312 612 601,040 48,648 45,927 35,166 546,062 

2018 14 MISCELLANEOUS 2,241,196 653,831 45,776 3,624,653 600,107 12,532 124,137 

2018 

Total 22,645,302 792,678 2,722,636 4,548,634 1,194,728 2,169,725 3,910,170 
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Appendix E MACTEC, Inc. 230

 

APPENDIX E: 

AIRCRAFT PM EXCERPT FROM 2001 TUCSON REPORT 
Final Report 

EMISSIONS INVENTORIES FOR 

THE TUCSON AIR PLANNING AREA 

VOLUME I. STUDY DESCRIPTION AND RESULTS 

Prepared for 

Pima Association of Governments 

177 N. Church Avenue, Suite 405 

Tucson, AZ 85701 

Prepared by 

Marianne Causley 

Rumla, Inc. 

3243 Gloria Terrace 

Lafayette, CA 94549 

Daniel Meszler 

Energy and Environmental Analysis, Inc. 

1655 North Fort Myer Drive 

Arlington, VA 22209 

Russell Jones 

Stratus Consulting, Inc. 

P.O. Box 4059 

Boulder, CO 80306-4059 

Steven Reynolds 

Envair 

12 Palm Avenue 

San Rafael, CA 94901 

November 2001
Emissions Inventories for the Tucson Air Planning Area 

Tucson Aircraft PM.doc i Final Report —November 2001

ACKNOWLEDGEMENTS

The authors extend their appreciation to the many individuals that contributed to this study. 

Particular thanks go to the staff of the Pima Association of Governments. Darcy Anderson was 

instrumental in providing definition at the outset of the study. Lee Comrie and Natalie Barnes 

provided considerable assistance with the emissions surveys, made many thoughtful suggestions 

and contributions throughout the study, and provided helpful comments on the draft final report. 

Kwame Agyare, Wayne Byrd and Bill Maxwell of the Pima County Department of 

Environmental Quality offered valuable assistance in providing socioeconomic and PDEQ permit 

data and in sharing their knowledge of emissions sources in the Tucson Air Planning Area. Dan 

Catlin of the Arizona Department of Environmental Quality provided insightful comments 

during the course of the study and reviewed the draft final report. 

Many individuals in the Tucson area participated in the annual and day-specific emissions 

surveys conducted as part of this study. The information they provided is sincerely appreciated. 

We also wish to acknowledge Patricia El-Gasseir and Helen Fugate of Rumla, Inc. for their 

dedicated efforts in building the facilities database. 
Emissions Inventories for the Tucson Air Planning Area 

Tucson Aircraft PM.doc iii Final Report —November 2001

TABLE OF CONTENTS

ACKNOWLEDGEMENTS ...................................................................................... i 

LIST OF TABLES .................................................................................................... viii 

LIST OF FIGURES................................................................................................... xiii 

ABBREVIATIONS AND ACRONYMS.................................................................. xiv 

EXECUTIVE SUMMARY....................................................................................... ES-1 

1 BACKGROUND................................................................................................... 1-1 

 1.1 Current Air Quality Status of the Tucson Area....................................... 1-1 

 1.1.1 Ozone ................................................................................................ 1-1 

 1.1.2 Carbon Monoxide.............................................................................. 1-3 

 1.1.3 Particulate Matter .............................................................................. 1-3 

 1.2 Overview of the Emissions Inventories................................................... 1-4 

 1.3 Emissions Support for Photochemical Modeling in Tucson................... 1-6 

 1.4 Organization of This Report.................................................................... 1-7 

2 POINT SOURCES ................................................................................................ 2-1 

 2.1 Identification of Sources ......................................................................... 2-1 

 2.2 Data Collection........................................................................................ 2-2 

 2.3 Data Entry ............................................................................................... 2-4 

 2.4 Calculation Methodologies ..................................................................... 2-5 

 2.4.1 Emissions Based on 2000 Actual Data ............................................. 2-6 

 2.4.2 Emissions Based on Adjustment of 1999 Data ................................. 2-7 

 2.4.3 Emissions Based on General Activity Data....................................... 2-7 

 2.4.4 Emissions Based on Evaporative Processes...................................... 2-8 

 2.5 Data Quality and Completeness .............................................................. 2-9 

 2.6 Future Year Estimations.......................................................................... 2-11 

 2.7 Point Source Emissions Summary .......................................................... 2-12 

 2.8 Temporal Activity Data........................................................................... 2-13 

 2.8.1 Point Source TAF Comparison ......................................................... 2-15 

 2.8.2 Point and Area TAF Comparison...................................................... 2-16 

3 STATIONARY AREA SOURCES ...................................................................... 3-1 

3.1 Architectural Coating .................................................................. 3-4 

3.1.1 Methodology....................................................................................... 3-4 

3.1.2 Calculations ........................................................................................ 3-5 

3.2 Asphalt Paving.......................................................................................... 3-6 

3.2.1 Methodology....................................................................................... 3-6 

3.2.2 Calculations ........................................................................................ 3-7 
Emissions Inventories for the Tucson Air Planning Area 

Tucson Aircraft PM.doc iv Final Report —November 2001

TABLE OF CONTENTS (Continued) 

3.3 Automobile Refinishing ........................................................................... 3-7 

3.3.1 Methodology....................................................................................... 3-7 

3.3.2 Calculations ........................................................................................ 3-8 

3.4 Commercial Bakeries ............................................................................... 3-9 

3.4.1 Methodology....................................................................................... 3-9 

3.4.2 Calculations ........................................................................................ 3-9 

3.5 Consumer Solvent Usage ......................................................................... 3-10 

3.5.1 Methodology....................................................................................... 3-10 

3.5.2 Calculations ........................................................................................ 3-10 

3.6 Dry Cleaning............................................................................................. 3-11 

3.6.1 Methodology....................................................................................... 3-11 

3.6.2 Calculations ........................................................................................ 3-12 

3.7 Forest Fires and Prescribed Burnings....................................................... 3-13 

3.7.1 Methodology....................................................................................... 3-13 

3.7.2 Calculations ........................................................................................ 3-13 

3.8 Gasoline Distribution ............................................................................... 3-15 

3.8.1 Methodology....................................................................................... 3-15 

3.8.2 Calculations ........................................................................................ 3-17 

3.9 Graphic Arts ............................................................................................. 3-18 

3.9.1 Methodology....................................................................................... 3-18 

3.9.2 Calculations ........................................................................................ 3-18 

3.10 Industrial Surface Coating........................................................................ 3-18 

3.10.1 Methodology....................................................................................... 3-19 

3.10.2 Calculations ........................................................................................ 3-19 

3.11 Misc. Residential/Commercial Fuel Combustion .................................... 3-20 

3.11.1 Methodology....................................................................................... 3-20 

3.11.2 Calculations ........................................................................................ 3-21 

3.12 Pesticide Application................................................................................ 3-23 

3.12.1 Methodology....................................................................................... 3-24 

3.12.2 Calculations ........................................................................................ 3-25 

3.13 Residential Wood Combustion................................................................. 3-25 

3.13.1 Methodology....................................................................................... 3-26 

3.13.2 Calculations ........................................................................................ 3-26 
Emissions Inventories for the Tucson Air Planning Area 

Tucson Aircraft PM.doc v Final Report —November 2001

TABLE OF CONTENTS (Continued) 

3.14 Solvent Cleaning ...................................................................................... 3-28 

3.14.1 Methodology....................................................................................... 3-28 

3.14.2 Calculations ........................................................................................ 3-29 

3.15 Structure and Vehicle Fires ..................................................................... 3-29 

3.15.1 Methodology....................................................................................... 3-30 

3.15.2 Calculations ........................................................................................ 3-30 

3.16 Traffic Markings....................................................................................... 3-32 

3.16.1 Methodology....................................................................................... 3-32 

3.16.2 Calculations ........................................................................................ 3-33 

3.17 Area Source Annual Emissions Summaries............................................. 3-33 

3.18 Day-specific Area Source Emissions Summaries..................................... 3-41 

4 NONROAD MOBILE SOURCES........................................................................ 4-1 

 4.1 Introduction ............................................................................................. 4-1 

4.2 General Use Nonroad Equipment............................................................ 4-4 

 4.2.1 Basic Inventory Methodology ........................................................... 4-6 

 4.2.2 NONROAD Model Inputs................................................................. 4-11 

 4.2.3 Emission Estimates for Calendar Year 2000..................................... 4-14 

 4.2.4 Emissions Estimates for Tuesday August 22, 2000 .......................... 4-17 

 4.2.5 Emissions Estimates for Sunday September 10, 2000 ...................... 4-21 

 4.2.6 Emissions Estimates for Saturday April 14, 2001............................. 4-21 

 4.2.7 Emissions Estimates for Tuesday April 24, 2001 ............................. 4-22 

 4.2.8 Emissions Estimates for Calendar Year 2005 ................................... 4-24 

 4.2.9 Emissions Estimates for Calendar Year 2010 ................................... 4-25 

 4.2.10 Temporal Allocation Factors for General Use Nonroad Equipment. 4-27 

 4.3 Aircraft Operations........................................................................................ 4-28 

 4.3.1 Commercial Air Carrier Emission Estimates for Calendar Year 2000 4-30 

4.3.2 Commercial Air Carrier APU Emission Estimates for 

 Calendar Year 2000.................................................................. 4-44 

 4.3.3 Other Aircraft Emissions for Calendar Year 2000............................ 4-45 

 4.3.4 Other Potential Aircraft Emissions Sources Not Currently Considered 4-64 

 4.3.5 Aircraft Emissions Estimates for Tuesday August 22, 2000............. 4-68 

 4.3.6 Aircraft Emissions Estimates for Sunday September 10, 2000......... 4-69 

 4.3.7 Aircraft Emissions Estimates for Saturday April 14, 2001 ............... 4-70 

 4.3.8 Aircraft Emissions Estimates for Tuesday April 24, 2001................ 4-70 

 4.3.9 Aircraft Emissions Estimates for Calendar Year 2005 ..................... 4-77 

 4.3.10 Aircraft Emissions Estimates for Calendar Year 2010 ..................... 4-83 

 4.3.11 Day-Specific and Forecast Aircraft Emission Estimates for TIA ..... 4-88 

 4.3.12 Temporal Allocation Factors for Aircraft Emissions........................ 4-88 
Emissions Inventories for the Tucson Air Planning Area 

Tucson Aircraft PM.doc vi Final Report —November 2001

TABLE OF CONTENTS (Continued)

4.4 Aircraft Ground Support Equipment 4-88 

 4.4.1 GSE Emissions Estimates for Calendar Year 2000 .......................... 4-94 

 4.4.2 GSE Emissions Estimates for Tuesday August 22, 2000.................. 4-102 

 4.4.3 GSE Emissions Estimates for Sunday September 10, 2000.............. 4-104 

 4.4.4 GSE Emissions Estimates for Saturday April 14, 2001 .................... 4-104 

 4.4.5 GSE Emissions Estimates for Tuesday April 24, 2001..................... 4-108 

 4.4.6 GSE Emissions Estimates for Calendar Year 2005 .......................... 4-108 

 4.4.7 GSE Emissions Estimates for Calendar Year 2010 .......................... 4-108 

 4.4.8 Temporal Allocation Factors for GSE Emissions ............................. 4-108 

4.5 Commercial Marine Operations .................................................................... 4-113 

4.6 Locomotive Operations ................................................................................. 4-113 

 4.6.1 Locomotive Emission Estimates for Calendar Year 2000 ................ 4-114 

4.6.2 Day-Specific Locomotive Emission Estimates for 

 Calendar Year 2000................................................................. 4-124 

4.6.3 Day-Specific Locomotive Emission Estimates for 

 Calendar Year 2001.................................................................. 4-125 

4.6.4 Locomotive Emission Estimates for 

 Calendar Years 2005 and 2010 ................................................ 4-125 

 4.6.5 Temporal Allocation Factors for Locomotive Emissions ................. 4-125 

5 MODEL INVENTORY PREPARATION ........................................................... 5-1 

 5.1 Overview ....................................................................................................... 5-1 

 5.1.1 Spatial Resolution of Emissions........................................................ 5-2 

 5.1.2 Temporal Resolution of Emissions ................................................... 5-2 

 5.1.3 Chemical Resolution of Emissions ................................................... 5-3 

 5.2 Inventory Preparation .................................................................................... 5-3 

 5.2.1 Emission Data ................................................................................... 5-6 

 5.2.2 Spatial Allocation.............................................................................. 5-6 

 5.2.3 Temporal Allocation ......................................................................... 5-11 

 5.2.4 Chemical Speciation.......................................................................... 5-11 

 5.3 Emission Processing System......................................................................... 5-12 

 5.3.1 Output Formats.................................................................................. 5-12 

 5.4 Summary of Modeling Inventories................................................................ 5-14 

6 DATA QUALITY REVIEW................................................................................ 6-1 

 6.1 Point Sources................................................................................................. 6-1 

 6.2 Area Sources ................................................................................................. 6-3 

 6.3 Nonroad Mobile Sources............................................................................... 6-4 

 6.4 Photochemical Air Quality Model Input Files .............................................. 6-5 

 6.5 External Review ............................................................................................ 6-6 

 6.6 Overall Comments on the Inventories........................................................... 6-9 

7 REFERENCES..................................................................................................... 7-1 
Emissions Inventories for the Tucson Air Planning Area 

Tucson Aircraft PM.doc vii Final Report —November 2001

TABLE OF CONTENTS (Concluded) 

 APPENDIX 2A. LIST OF PAG MAJOR AND MINOR FACILITIES 

 CONTACTED DURING SURVEY ACTIVITIES .......................... 2A-1 

 APPENDIX 2B. REVISED ANNUAL SURVEY FORM FOR 

 MAJOR FACILITIES ....................................................................... 2B-1 

 APPENDIX 2C. REVISED ANNUAL SURVEY FORMS FOR 

 MINOR FACILITIES........................................................................ 2C-1 

 APPENDIX 2D. PAG 2000 TOTAL EMISSIONS BY FACILITY ................... 2D-1 

 APPENDIX 3A. ASC SPATIAL ALLOCATION SURROGATE ASSIGNMENT 3A-1 

 APPENDIX 4A. NONROAD MOBILE SOURCE EMISSIONS BY SCC........ 4A-1 

 

 APPENDIX 4B. NONROAD MOBILE SOURCE TEMPORAL 

 ALLOCATION FACTORS .............................................................. 4B-1 

APPENDIX 5A. NATIONAL EMISSION INVENTORY (NEI) 

 RECORD FORMATS....................................................................... 5A-1 

APPENDIX 5B. SPATIAL ALLOCATION OF EMISSIONS USING GIS....... 5B-1 

APPENDIX 5C. EDBsys EMISSION OUTPUT FORMATS............................. 5C-1 
Emissions Inventories for the Tucson Air Planning Area 

Tucson Aircraft PM.doc viii Final Report —November 2001

LIST OF TABLES

Table 1-1. Inventories for the Tucson Air Planning Area ........................................... 1-2 

Table 2-1. PDEQ Permitted Facilities Flagged as a Major Point Source.................... 2-2 

Table 2-2. PAG Survey Response Rates ..................................................................... 2-4 

Table 2-3. NEI Record Elements for the PAG Inventory............................................ 2-5 

Table 2-4. 2000 Emission Estimates Adjustments from Surveys ............................... 2-7 

Table 2-5. Resolution of Survey Data Issues and Possible Inventory Effect .............. 2-9 

Table 2-6. Ranges of EGAS Growth Factors from 2000 Baseline.............................. 2-12 

Table 2-7. Annual Emissions Estimates for Major and Minor Point Sources ............ 2-12 

Table 2-8. Day-specific Criteria Pollutant Totals (tons per day) ................................ 2-13 

Table 2-9. Survey Responses for Temporal Activity Profile Information .................. 2-14 

Table 3-1. TAPA Inventory Area Source Categories ................................................. 3-1 

Table 3-2. Socioeconomic Parameters Applied to 2000 and Projected Year 

 Emission Estimations........................................................................... 3-3 

Table 3-3. Projection Factors for the 2005 and 2010 Emission Estimates.................. 3-3 

Table 3-4. Allocation Adjustment Factors .................................................................. 3-3 

Table 3-5. Architectural Coatings Gallons Per Capita Calculations........................... 3-5 

Table 3-6. TAPA Annual Architectural Coating VOC Emission Estimates............... 3-6 

Table 3-7. Growth Factors for the Automobile Refinishing Employment 

 in the Tucson Area ............................................................................... 3-8 

Table 3-8. TAPA Annual Automobile Refinishing VOC Emissions.......................... 3-8 

Table 3-9. Commercial Bakery Process Emission Factors ......................................... 3-10 

Table 3-10. TAPA Bakeries VOC Emission Estimates .............................................. 3-10 

Table 3-11. TAPA Consumer Product Per Capita Factors and 

 Emission Estimates (tons) ................................................................... 3-11 

Table 3-12. Dry Cleaning Telephone Survey Responses ............................................ 3-12 

Table 3-13. Pima County Acres Burned During 2000 ................................................ 3-13 

Table 3-14. Emission Factors for Estimation of Forest Fire and Prescribed Burnings 3-14 

Table 3-15. TAPA 2000 Emissions from Forest Fires and Prescribed Burnings (tons) 3-14 

Table 3-16. TAPA 2005 and 2010 Emissions from Forest Fires and Prescribed 

 Burnings (tons/year) ............................................................................. 3-15 

Table 3-17. Year 2000 Gasoline Tax Sales (gallons) ................................................. 3-16 

Table 3-18. TAPA VOC Emissions from Gasoline Marketing Activities (tons) ....... 3-17 

Table 3-19. TAPA VOC Emissions from Graphic Arts (tons) .................................. 3-18 

Table 3-20. ZIP Codes Included for Dun & Bradstreet Extraction ............................. 3-19 

Table 3-21. TAPA VOC Emission Estimates for Industrial Surface Coating (tons) . 3-20 

Table 3-22. Natural Gas and LPG Emission Factors ................................................. 3-21 

Table 3-23. 2000 Natural Gas and LPG Sales for the Tucson Area............................ 3-22 

Table 3-24. TAPA 2000 Emissions from Miscellaneous Combustion (tons/year) .... 3-22 

Table 3-25. TAPA 2005 Emissions from Miscellaneous Combustion (tons/year) .... 3-23 

Table 3-26. TAPA 2010 Emissions from Miscellaneous Combustion (tons/year)..... 3-23 
Emissions Inventories for the Tucson Air Planning Area 

Tucson Aircraft PM.doc ix Final Report —November 2001

LIST OF TABLES (Continued) 

Table 3-27. Identified Survey Contacts and Responses for the Source 

 Category Pesticide Application........................................................... 3-24 

Table 3-28. Growth Factors for the Dwelling Units in the Tucson Area.................... 3-26 

Table 3-29. Tons of Wood Burned by Type................................................................ 3-27 

Table 3-30. Residential Wood Burning Emission Factors (lbs/ton burned) .............. 3-27 

Table 3-31. Annual Emissions from Residential Wood Burning by Device (tons) .... 3-28 

Table 3-32. TAPA Annual VOC Emission Estimates from Solvent Cleaning (tons) 3-29 

Table 3-33. 2000 Fire Incident Counts for Structural and Vehicle Fires .................... 3-31 

Table 3-34. Emission Factors for Structural and Vehicular Fires............................... 3-31 

Table 3-35. Annual TAPA Emissions from Structure and Vehicle Fires (tons) ........ 3-32 

Table 3-36. TAPA Emissions from Traffic Markings ................................................ 3-33 

Table 3-37. TAPA Inventory Area Source Categories Estimation Methods .............. 3-35 

Table 3-38. TAPA 2000 Annual Area Source Emissions by Source Category (tons) 3-36 

Table 3-39. TAPA 2005 Annual Area Source Emissions by Source Category (tons) 3-38 

Table 3-40. TAPA 2010 Annual Area Source Emissions by Source Category (tons) 3-40 

Table 3-41. TAPA August 22, 2000 Area Source Emissions by Source Category..... 3-43 

Table 3-42. TAPA September 10, 2000 Area Source Emissions by Source Category 3-45 

Table 3-43. TAPA April 24, 2001 Area Source Emissions by Source Category........ 3-47 

Table 4-1. Nonroad Mobile Source Equipment Categories ........................................ 4-2 

Table 4-2. NONROAD Model Equipment Allocation Parameters............................. 4-10 

Table 4-3. Retail Fuel Test Data for 2000................................................................... 4-12 

Table 4-4. NONROAD Model Fuel Input Parameters................................................ 4-14 

Table 4-5. NONROAD Model Temperature Input Parameters................................... 4-14 

Table 4-6. TAPA General Use Nonroad Equipment Emission Inventory 

 for 2000 (tons per year) ........................................................................... 4-15 

Table 4-7. Allocation Factors used to Convert County to TAPA Emission Estimates 4-18 

Table 4-8. NONROAD Model Input Parameters for Day-Specific Inventories....... 4-18 

Table 4-9. TAPA General Use Nonroad Equipment Emission Inventory for 

 Tuesday August 22, 2000 (tons per day)........................................... 4-19 

Table 4-10. NONROAD Model Monthly Activity Allocation Factors.................... 4-20 

Table 4-11. NONROAD Model Day-of-Week Activity Allocation Factors............ 4-20 

Table 4-12. TAPA General Use Nonroad Equipment Emission Inventory for 

 Sunday September 10, 2000 (tons per day)....................................... 4-22 

Table 4-13. TAPA General Use Nonroad Equipment Emission Inventory for 

 Saturday April 14, 2001 (tons per day) ............................................. 4-23 

Table 4-14. TAPA General Use Nonroad Equipment Emission Inventory for 

 Tuesday April 24, 2001 (tons per day).............................................. 4-24 

Table 4-15. NONROAD Model Fuel Input Parameters for 2005 and 2010 ............ 4-26 

Table 4-16. TAPA General Use Nonroad Equipment Emission Inventory for 

 2005 (tons per year)........................................................................... 4-26 
Emissions Inventories for the Tucson Air Planning Area 

Tucson Aircraft PM.doc x Final Report —November 2001

LIST OF TABLES (Continued) 

Table 4-17. TAPA General Use Nonroad Equipment Emission Inventory for 

 2010 (tons per year)........................................................................... 4-28 

Table 4-18. 1999 FAA Commercial Air Carrier Data for TIA .................................. 4-31 

Table 4-19. 1999 Aircraft Operations Data Reported by TIA.................................... 4-33 

Table 4-20. 2000 Aircraft Operations Data for TIA................................................... 4-35 

Table 4-21. TIA Taxi Time Data as Reported by U.S. DOT (minutes) ..................... 4-35 

Table 4-22. TIA Mixing Height Data......................................................................... 4-37 

Table 4-23. Statistics for Aircraft and APU PM Relations ........................................ 4-42 

Table 4-24. TIA Emission Inventory for 2000 (tons per year)................................... 4-44 

Table 4-25. APU Usage Rates at TIA ........................................................................ 4-46 

Table 4-26. Aircraft Activity Other Than Commercial Air Carriers in 2000............. 4-47 

Table 4-27. National Distribution of General Aviation and Air Taxi Aircraft .......... 4-50 

Table 4-28. Comparison of LTO-Specific Emission Rates for General Aviation 

 and Air Taxi Aircraft (pounds per LTO)............................................. 4-50 

Table 4-29. Local Distribution of General Aviation and Air Taxi Aircraft ............... 4-51 

Table 4-30. EPA Default TIM Data for General Aviation and Air Taxi Aircraft 

 (minutes per LTO)............................................................................... 4-52 

Table 4-31. Methodology Used to Develop Taxi/Idle Times for Local General 

 Aviation and Air Taxi Aircraft............................................................ 4-53 

Table 4-32. Local Taxi/Idle TIM Data for General Aviation and Air Taxi Aircraft 

 (minutes per LTO)............................................................................... 4-54 

Table 4-33. Local TIM Data for General Aviation and Air Taxi Aircraft 

 (minutes per LTO)............................................................................... 4-55 

Table 4-34. Based General Aviation and Air Taxi Aircraft in 2000.......................... 4-56 

Table 4-35. Local Taxi/Idle TIM Data for General Aviation and Air Taxi Aircraft 

 (minutes per LTO)............................................................................... 4-58 

Table 4-36. Military Aircraft Distributions for 2000 ................................................. 4-61 

Table 4-37. EPA Default TIM Data for Military Aircraft (minutes per LTO)........... 4-61 

Table 4-38. Local and TIM Data for Military Aircraft (minutes per LTO)................ 4-62 

Table 4-39. Aircraft Emissions for Operations other than Commercial Air 

 Carriers in 2000 (tons per year)........................................................... 4-65 

Table 4-40. Total Aircraft and APU Emissions in 2000 by Airport (tons per year) .. 4-66 

Table 4-41. Total Aircraft and APU Emissions in 2000 by Aircraft Type 

 (tons per year)...................................................................................... 4-66 

Table 4-42. Other Potential Aircraft Activity Locations............................................ 4-68 

Table 4-43. Day-of-Week Allocation Factors for Aircraft......................................... 4-70 

Table 4-44. Aircraft Emissions for Operations other than Commercial Air Carriers 

 On Tuesday August 22, 2000 (tons per day)....................................... 4-71 

Table 4-45. Total Aircraft and APU Emissions on Tuesday August 22, 2000 by 

 Airport (tons per day) .......................................................................... 4-72 

Table 4-46. Total Aircraft and APU Emissions on Tuesday August 22, 2000 by 

 Aircraft Type (tons per day) ................................................................ 4-72 
Emissions Inventories for the Tucson Air Planning Area 

Tucson Aircraft PM.doc xi Final Report —November 2001

LIST OF TABLES (Continued) 

Table 4-47. Aircraft Emissions for Operations other than Commercial Air Carriers 

 On Sunday September 10, 2000 (tons per day)................................... 4-73 

Table 4-48. Total Aircraft and APU Emissions on Sunday September 10, 2000 

 By Airport (tons per day)..................................................................... 4-74 

Table 4-49. Total Aircraft and APU Emissions on Sunday September 10, 2000 

 By Aircraft Type (tons per day)........................................................... 4-74 

Table 4-50. Aircraft Emissions for Operations other than Commercial Air Carriers 

 On Saturday April 14, 2001 (tons per day) ......................................... 4-75 

Table 4-51. Total Aircraft and APU Emissions on Saturday April 14, 2001 by 

 Airport (tons per day) .......................................................................... 4-76 

Table 4-52. Total Aircraft and APU Emissions on Saturday April 14, 2001 by 

 Aircraft Type (tons per day) ................................................................ 4-76 

Table 4-53. Aircraft Emissions for Operations other than Commercial Air Carriers 

 On Tuesday April 24, 2001 (tons per day) .......................................... 4-78 

Table 4-54. Total Aircraft and APU Emissions on Tuesday April 24, 2001 by 

 Airport (tons per day) .......................................................................... 4-79 

Table 4-55. Total Aircraft and APU Emissions on Tuesday April 24, 2001 by 

 Aircraft Type (tons per day) ................................................................ 4-79 

Table 4-56. Aircraft Operational Growth Ratios (Forecast Year/2000 Activity)....... 4-80 

Table 4-57. Aircraft Operations Summary................................................................. 4-81 

Table 4-58. Based Aircraft Summary......................................................................... 4-82 

Table 4-59. Aircraft Emissions for Operations other than Commercial Air Carriers 

 in 2005 (tons per year)......................................................................... 4-84 

Table 4-60. Total Aircraft and APU Emissions in 2005 by Airport (tons per year) .. 4-85 

Table 4-61. Total Aircraft and APU Emissions in 2005 by Aircraft Type 

 (tons per year)...................................................................................... 4-85 

Table 4-62. Aircraft Emissions for Operations other than Commercial Air Carriers 

 in 2010 (tons per year)......................................................................... 4-86 

Table 4-63. Total Aircraft and APU Emissions in 2010 by Airport (tons per year) .. 4-87 

Table 4-64. Total Aircraft and APU Emissions in 2010 by Aircraft Type 

 (tons per year)...................................................................................... 4-87 

Table 4-65. TIA Emission Inventory for Tuesday August 22, 2000 (tons per day) ... 4-89 

Table 4-66. TIA Emission Inventory for Sunday September 10, 2000 

 (tons per day)....................................................................................... 4-89 

Table 4-67. TIA Emission Inventory for Saturday April 14, 2001 (tons per day) ..... 4-90 

Table 4-68. TIA Emission Inventory for Tuesday April 24, 2001 (tons per day) ...... 4-90 

Table 4-69. TIA Emission Inventory for 2005 (tons per year)................................... 4-91 

Table 4-70. TIA Emission Inventory for 2010 (tons per year)................................... 4-91 

Table 4-71. Aircraft Ground Support Equipment Reported by TIA .......................... 4-95 

Table 4-72. Aircraft Ground Support Equipment Reported by DM .......................... 4-97 

Table 4-73. Summary of Reported and Additional GSE Types................................. 4-99 

Table 4-74. Summary (Average) GSE Statistics for TIA........................................... 4-100 
Emissions Inventories for the Tucson Air Planning Area 

Tucson Aircraft PM.doc xii Final Report —November 2001

LIST OF TABLES (Concluded) 

Table 4-75. Summary (Average) GSE Statistics for DM........................................... 4-101 

Table 4-76. GSE Model LTO, Fuel, Temperature, and Humidity Input Parameters . 4-102 

Table 4-77. GSE Emission Inventories for Calendar Year 2000 (tons per year) ....... 4-103 

Table 4-78. GSE Emission Inventories for Tuesday August 22, 2000 

 (tons per day)....................................................................................... 4-105 

Table 4-79. GSE Emission Inventories for Sunday September 10, 2000 

 (tons per day)....................................................................................... 4-106 

Table 4-80. GSE Emission Inventories for Saturday April 14, 2001 (tons per day).. 4-109 

Table 4-81. GSE Emission Inventories for Tuesday April 24, 2001 (tons per day)... 4-110 

Table 4-82. GSE Emission Inventories for Calendar Year 2005 (tons per year) ....... 4-111 

Table 4-83. GSE Emission Inventories for Calendar Year 2010 (tons per year) ....... 4-112 

Table 4-84. Fuel Consumption Indices for Union Pacific Railroad........................... 4-115 

Table 4-85. Union Pacific Railroad Gross Ton Miles for Pima County Track 

 Segments ............................................................................................. 4-117 

Table 4-86. Union Pacific Railroad Fuel Consumption in the TAPA ....................... 4-118 

Table 4-87. Forecasted Union Pacific Railroad Fuel Consumption in the TAPA ..... 4-121 

Table 4-88. Locomotive Emission Control Impacts on Fleetwide Emission Rates 

 For Union Pacific Railroad ................................................................. 4-121 

Table 4-89. Locomotive Emission Factors for Union Pacific Railroad 

 (pounds per gallon of fuel consumed)................................................. 4-123 

Table 4-90. Annual Locomotive Emission Estimates for the TAPA (tons per year). 4-124 

Table 4-91. Day-Specific Locomotive Emission Estimates for the TAPA 

 (tons per year)...................................................................................... 4-126 
Emissions Inventories for the Tucson Air Planning Area 

Tucson Aircraft PM.doc xiii Final Report —November 2001

LIST OF FIGURES 

Figure 2-1. Total Hours of Operation by Day of Week.............................................. 2-14 

Figure 2-2. PAG 190 Hourly Activity Profiles........................................................... 2-16 

Figure 2-3. PAG 095 Hourly Activity Profiles........................................................... 2-17 

Figure 2-4. PAG 095 Day-of-Week Activity Profiles................................................ 2-17 

Figure 2-5. PAG 095 Monthly Activity Profiles ........................................................ 2-18 

Figure 3-1. TAPA 2000 VOC Emissions................................................................... 3-34 

Figure 3-2. TAPA 2000 NOx Emissions ................................................................... 3-34 

Figure 3-3. TAPA August 22, 2000 Area Source VOC Emissions ........................... 3-49 

Figure 3-4. TAPA August 22, 2000 Area Source NOx Emissions ............................ 3-49 

Figure 3-5. TAPA September 10, 2000 Area Source VOC Emissions...................... 3-50 

Figure 3-6. TAPA September 10, 2000 Area Source NOx Emissions....................... 3-50 

Figure 3-7. TAPA April 24, 2001 Area Source VOC Emissions............................... 3-51 

Figure 3-8. TAPA April 24, 2001 Area Source NOx Emissions ............................... 3-51 

Figure 4-1. Relationship Used to Estimate Aircraft PM Emission Rates .................. 4-42 

Figure 4-2. Class I Railroad Freight Movement Since 1970.................................... 4-119 

Figure 4-3. Class I Railroad Energy Intensity Since 1970 ....................................... 4-120 

Figure 4-4. Fleetwide Locomotive Emission Reductions .......................................... 4-122 

Figure 5-1. Episodic Day Inventories for the Tucson Air Planning Area .................. 5-4 

Figure 5-2. Modeling Inventory Processing Input Data ............................................. 5-5 

Figure 5-3. Spatial Allocation Factor Surrogate Definition for the TAPA ................ 5-7 

Figure 5-4. Carbon-bond Mechanism Species Gram Molecular Weights 

 for Reporting ....................................................................................... 5-15 

Figure 5-5. Modeling Input Emissions Totals for the August 22nd 

 Typical Summer Day (tons/day)......................................................... 5-15 

Figure 5-6. Day-specific Modeling Input Emissions Totals (tons) ............................ 5-16 

Figure 6-1. Diurnal Variation of Stationary Area Source NO Emissions 

(g-mole/hour) in Grid Cell (105,120) from the Typical 

 Summer Day 2000 UAM Input File.................................................... 6-7 

Figure 6-2. Gridded Stationary Area Source Paraffin Emissions (g-mole/hour) 

 at 1 PM from the Typical Summer Day 2000 UAM Input File .......... 6-8 
Emissions Inventories for the Tucson Air Planning Area 

Tucson Aircraft PM.doc xiv Final Report —November 2001

 

ABBREVIATIONS AND ACRONYMS 

ADEQ Arizona Department of Environmental Quality 

ADWM Arizona Department of Weights and Measures 

ALD2 High Molecular Weight Aldehydes (RCHO, R≠H) 

AML Arc Macro Language 

AQM Air Quality Model 

APU Aircraft Power Unit 

ARB California Air Resources Board 

ASC Area Source Category Code 

AT Air Taxi 

CNG Compressed Natural Gas 

CO Carbon Monoxide 

CSF Chemical Speciation Factor 

DM Davis-Monthan Air Force Base 

DOT Department of Transportation 

EDMS Emissions Dispersion Modeling System 

EEA Energy & Environmental Analysis, Inc. 

EIPP Emission Inventory Preparation Plan 

EPA The U.S. Environmental Protection Agency 

ETH Ethene (CH2═CH2) 

FAA Federal Aviation Administration 

FAEED FAA Aircraft Engine Emission Database 

FIPS Federal Information Processing System 

FIRE EPA’s Factor Information REtrieval Data System 

FORM Formaldehyde (CH2═O) 

GA General Aviation 

GIS Geographical Information System 

GSE Ground Support Equipment 

ICAO International Civil Aviation Organization 
Emissions Inventories for the Tucson Air Planning Area 

Tucson Aircraft PM.doc xv Final Report —November 2001

ABBREVIATIONS AND ACRONYMS 

ISOP Isoprene 

LPG Liquid Petroleum Gas 

LTO Landing and TakeOff 

NAD27 North American Datum - 1927 

NCDC National Climatic Data Center 

NEI US EPA National Emission Inventory 

NEVES Nonroad Engine and Vehicle Emission Study 

NG Natural Gas 

NO Nitric Oxide 

NO2 Nitrogen Dioxide 

NOX Oxides of Nitrogen 

OLE Olefinic Carbon Bond (C═C) 

ORNL Oak Ridge National Laboratory 

PAG Pima Association of Governments 

PAR Paraffinic Carbon Bond (C—C) 

PDEQ Pima County Department of Environmental Quality 

PM Particulate Matter 

PM2.5 Particulate Matter less than 2.5 microns 

PM10 Particulate Matter less than 10 microns 

RASP Regional Aviation System Plan 

RVP Reid Vapor Pressure 

SAF Spatial Allocation Factor 

SCC Source Category Code 

SCF Standard Cubic Foot 

SIC Standard Industrial Classification 

SIP State Implementation Plan 

SO2 Sulfur Dioxide 

SOX Oxides of Sulfur 

TAF Temporal Allocation Factor 
Emissions Inventories for the Tucson Air Planning Area 

Tucson Aircraft PM.doc xvi Final Report —November 2001

ABBREVIATIONS AND ACRONYMS 

TAPA Tucson Air Planning Area 

TAZ Transportation Analysis Zone 

THC Total Hydrocarbon 

TIA Tucson International Airport 

TIM Time-In-Mode 

TOL Tolulene (C6H5—CH3) 

TTN EPA Technology Transfer Network 

UAM Urban Airshed Model 

UP Union Pacific Railroad 

VOC Volatile Organic Compounds as defined by the 1990 Clean Air 

Act Amendments 

XYL Xylene (C6H6—(CH3)2) 

 

 

 

 

 
Emissions Inventories for the Tucson Air Planning Area 

PAGf-Sect4.doc 4-40 Final Report – November 2001

(Prior material unrelated to VISTAS modeling is intentionally omitted) 

While emission rates for HC, CO, and NOx are routinely measured from (new) commercial air 

carrier engines under the emissions certification component of International Civil Aviation 

Organization (ICAO) regulations, measurement of PM emissions is not required. As a result, 

almost all aircraft engine PM emission rate data have been collected under special studies. 

Currently, such data exists for only about 20 aircraft engines, with a considerable portion of these 

data collected by the U.S. Air Force for military aircraft engines. While emission factors for 

these engines are included in the AP-42 database upon which the FAEED and EDMS emission 

inventory models were developed, they have not been included in either model due to their 

limited applicability. To date, it has been standard EPA practice not to estimate PM emissions 

for aircraft engines. However, since the emissions models maintain a placekeeper for PM 

emission rates and include PM emission estimates for GSE, it can appear to the uninformed user 

that aircraft PM emission rates are zero. As a result, aircraft are often incorrectly considered to be 

insignificant PM sources even though those engines tested for PM have demonstrated significant 

emission rates. This policy of exclusion by omission is not appropriate in developing an accurate 

modeling inventory, even in the absence of a large emissions database. While a precise 

emissions estimate cannot be made with available data, it is clear that a zero emission rate is far 

from accurate. 

As an alternative for this study, measured emissions data for aircraft engines that have been 

tested for PM were statistically analyzed to determine whether or not a relationship to other 

measured emissions parameters could be established. Intuitively, it was hoped that an inverse 

relationship with NOx might be demonstrated, as such a relationship is theoretically attractive. 

While the level of sophistication of the statistical analysis is constrained by the quantity of data 

available, simple direct and indirect linear relationships can be examined. Because data are not 

available for each test engine in each of the four LTO cycle modes and because relationships 

might be expected to vary by operating mode (due to significant changes in engine and 

combustion efficiency), all statistical analysis was performed for each operating mode 

individually. 
Emissions Inventories for the Tucson Air Planning Area 

PAGf-Sect4.doc 4-41 Final Report – November 2001

Statistically significant relationships were found for the direct linear analysis for three of the four 

LTO cycle modes. Significant in this context means that coefficient t-statistics for one or more 

of the other measured pollutants (HC, CO, or NOx) indicated a direct relationship with measured 

PM (at a confidence level exceeding 95 percent). In all cases, correlation coefficients were poor 

(as expected), suggesting a high level of variability and poor predictability of PM emissions for 

any given engine. Nevertheless, statistics were unbiased and should provide an accurate 

mechanism to initially assess PM emissions on a aggregate basis (i.e., over a range of aircraft 

engine models such as those associated with an analysis for an entire set of airport operations). 

Only at idle was no significant relation found, which is not surprising given relative engine 

inefficiency in this mode. 

The indirect linear analysis revealed a consistent and significant inverse relationship between PM 

and NOx based on calculated t-statistics. Correlation coefficients continue to be poor, but 

t-statistics are generally improved over those of the direct linear analysis (all developed inverse 

relations, including idle, were significant at the 99 percent confidence level). In selecting the 

most appropriate relationship for estimation of PM emission rates for non-tested aircraft engines, 

the statistical analysis that produced the best combination of a significant t-statistic, a relatively 

low root mean square error, and an intuitive engineering basis was identified. This was the 

inverse NOx relationship for the takeoff (i.e., full throttle) mode of operation. Figure 4-1 

illustrates the selected statistical relationship. 

With this relationship established, PM emission rate data for the other aircraft operating modes 

(i.e., the approach, taxi, and climbout modes) was statistically analyzed against observed PM 

emission rate data for the takeoff mode. Statistically significant relations were developed for all 

three modes. Table 4-23 presents the coefficients developed for these PM-to-PM regressions as 

well as the statistics for the PM-to-NOx regression developed for the takeoff mode. These four 

relations were used to develop a set of fleetwide PM emission factors based on measured takeoff 

NOx emission rates. These emission factors were then input into the EEA aircraft emissions 

model and used to generate PM emission estimates for TIA aircraft operations. 
Emissions Inventories for the Tucson Air Planning Area 

PAGf-Sect4.doc 4-42 Final Report – November 2001

FIGURE 4-1. Relationship Used to Estimate Aircraft PM Emission Rates 

TABLE 4-23. Statistics for Aircraft and APU PM Relations 

Statistical Parameter Takeoff PM Climbout PM Approach PM Taxi PM 

Predictive Parameter 1/Takeoff NOx Takeoff PM Takeoff PM Takeoff PM 

Coefficient 28.42 1.42 1.53 3.10 

Coefficient t-statistic 5.1 11.8 14.9 5.7 

Correlation Coefficient 0.30 0.84 0.91 0.56 

F-statistic 7.4 86.1 135.7 21.9 

Number of Observations 18 17 15 18 

(Subsequent material unrelated to VISTAS modeling is intentionally omitted) 

0

1

2

3

4

5

6

7

8

9

10

0 5 10 15 20 25 30 35 40 45

Takeoff NOx (lb/KlbF)

Takeoff PM (lb/KlbF)

Diamond-shaped markers represent actual data

points used in takeoff mode PM statistical analysis.

The plotted regression line represents the statistical

best fit relation between takeoff PM and takeoff NOx,

the equation for which is:

 Takeoff PM = 28.42 (1/Takeoff NOx)
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories 

Appendix F MACTEC, Inc. 232

APPENDIX F: 

COMPARISON OF BASE F AND BASE G ON-ROAD MOBILE EMISSIONS
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Appendix F 

233

Note: Base G is equivalent to the Best and Final inventory for onroad mobile sources. 

Base G Onroad Mobile Emissions (Annual Tons)

FIPSST 2002 2009 2018 2002 2009 2018 2002 2009 2018 2002 2009 2018 2002 2009 2018 2002 AL 125,768 76,065 44,503 156,460 100,693 42,622 1,303,508 902,469 594,725 6,827 802 654 3,861 3,136 2,193 2,768 FL 520,757 336,707 199,050 460,503 312,321 136,040 4,493,820 3,308,863 2,263,190 20,687 2,584 2,302 11,148 9,801 7,516 7,779 GA 279,975 192,773 99,464 304,309 207,024 92,113 2,699,650 1,956,263 1,303,529 12,043 1,568 1,325 7,165 6,005 4,406 5,110 KY 102,362 73,142 42,810 154,634 100,025 46,993 1,214,191 950,912 711,211 6,238 751 694 3,682 2,944 2,348 2,667 MS 86,811 51,600 28,699 110,672 69,952 27,620 853,774 602,257 394,247 4,566 532 401 2,828 2,250 1,479 2,089 NC 260,895 166,844 91,720 323,606 199,281 79,433 2,839,283 1,966,195 1,207,391 12,286 1,487 1,346 6,505 5,510 3,994 4,571 SC 114,861 71,781 41,866 138,940 91,471 39,348 1,226,555 878,825 588,536 5,909 713 584 3,414 2,831 1,986 2,473 TN 177,943 114,032 61,339 235,869 150,179 62,446 1,893,704 1,320,562 863,682 9,127 1,065 862 5,312 4,160 2,813 3,904 VA 157,989 95,694 55,992 219,835 132,699 57,192 2,136,288 1,435,359 954,463 8,196 1,067 949 4,499 3,706 2,922 3,067 WV 41,703 24,570 14,652 58,340 35,234 15,530 526,841 360,865 243,683 2,438 276 231 1,366 1,057 747 984 VISTAS 1,869,063 1,203,208 680,096 2,163,168 1,398,879 599,336 19,187,613 13,682,570 9,124,656 88,316 10,844 9,348 49,780 41,400 30,403 35,411 

Base F Onroad Mobile (Annual Tons)

FIPSST 2002 2009 2018 2002 2009 2018 2002 2009 2018 2002 2009 2018 2002 2009 2018 2002 AL 118,978 73,137 47,151 157,626 101,299 46,598 1,300,754 934,442 675,902 6,898 637 720 3,905 3,195 2,488 2,799 FL 438,761 293,423 192,096 402,099 284,737 134,465 4,022,000 3,090,443 2,306,759 18,802 1,911 2,289 10,185 9,027 7,691 7,126 GA 265,972 187,102 104,678 306,998 208,568 100,707 2,712,473 2,044,169 1,474,029 12,182 1,256 1,458 7,252 6,116 4,995 5,169 KY 96,202 63,210 38,814 154,093 97,731 43,014 1,195,656 932,296 669,891 5,988 587 651 3,728 3,008 2,283 2,699 MS 81,701 49,986 30,337 110,242 69,949 29,829 849,049 624,575 445,150 4,614 398 441 2,863 2,296 1,688 2,114 NC 272,594 167,894 87,718 290,873 207,670 83,399 2,677,118 2,192,253 1,238,802 12,482 1,314 1,323 6,733 5,874 4,299 4,754 SC 107,236 69,026 44,121 139,403 91,832 42,641 1,220,825 921,308 663,597 5,972 558 643 3,454 2,884 2,258 2,502 TN 168,389 109,716 63,916 233,324 147,591 66,879 1,881,893 1,359,880 961,929 9,202 833 944 5,349 4,247 3,199 3,927 VA 143,969 91,230 59,737 222,830 133,039 64,079 1,996,287 1,483,125 1,091,546 7,234 902 1,059 4,546 3,768 3,343 3,097 WV 39,581 23,914 15,375 60,335 36,000 16,940 533,258 379,272 273,900 2,495 228 255 1,399 1,099 844 1,005 VISTAS 1,733,382 1,128,638 683,942 2,077,822 1,378,416 628,551 18,389,312 13,961,764 9,801,505 85,868 8,622 9,783 49,414 41,513 33,086 35,191 

Emissions Change (Base G - Base F, Annual Tons) -- Positive Value Indicates Increase from Base F

FIPSST 2002 2009 2018 2002 2009 2018 2002 2009 2018 2002 2009 2018 2002 2009 2018 2002 AL 6,789 2,928 -2,647 -1,166 -606 -3,977 2,754 -31,973 -81,178 -71 165 -66 -45 -58 -295 -31 FL 81,997 43,284 6,955 58,404 27,584 1,575 471,820 218,420 -43,569 1,885 672 14 963 774 -175 653 GA 14,003 5,671 -5,214 -2,689 -1,544 -8,594 -12,823 -87,906 -170,500 -139 312 -133 -86 -111 -589 -59 KY 6,160 9,933 3,996 541 2,294 3,979 18,534 18,615 41,319 250 164 43 -46 -65 65 -32 MS 5,110 1,613 -1,638 430 3 -2,209 4,724 -22,319 -50,903 -48 134 -41 -35 -46 -209 -25 NC -11,699 -1,049 4,001 32,734 -8,389 -3,966 162,165 -226,057 -31,411 -196 174 23 -228 -364 -304 -183 SC 7,625 2,755 -2,255 -462 -362 -3,293 5,731 -42,483 -75,061 -63 156 -59 -40 -53 -272 -29 TN 9,554 4,316 -2,577 2,545 2,589 -4,433 11,811 -39,318 -98,246 -75 232 -82 -37 -87 -385 -22 VA 14,020 4,464 -3,744 -2,995 -340 -6,887 140,001 -47,766 -137,084 962 165 -110 -47 -62 -420 -30 WV 2,122 656 -723 -1,995 -766 -1,410 -6,416 -18,407 -30,217 -57 49 -24 -32 -42 -97 -22 VISTAS 135,680 74,570 -3,846 85,346 20,462 -29,215 798,301 -279,194 -676,850 2,448 2,222 -435 367 -114 -2,683 219 

Emissions Change (Base G - Base F/Base F, Annual %) -- Positive Value Indicates Increase from Base F

FIPSST 2002 2009 2018 2002 2009 2018 2002 2009 2018 2002 2009 2018 2002 2009 2018 2002 AL 6% 4% -6% -1% -1% -9% 0% -3% -12% -1% 26% -9% -1% -2% -12% -1% FL 19% 15% 4% 15% 10% 1% 12% 7% -2% 10% 35% 1% 9% 9% -2% 9% GA 5% 3% -5% -1% -1% -9% 0% -4% -12% -1% 25% -9% -1% -2% -12% -1% KY 6% 16% 10% 0% 2% 9% 2% 2% 6% 4% 28% 7% -1% -2% 3% -1% MS 6% 3% -5% 0% 0% -7% 1% -4% -11% -1% 34% -9% -1% -2% -12% -1% NC -4% -1% 5% 11% -4% -5% 6% -10% -3% -2% 13% 2% -3% -6% -7% -4% SC 7% 4% -5% 0% 0% -8% 0% -5% -11% -1% 28% -9% -1% -2% -12% -1% TN 6% 4% -4% 1% 2% -7% 1% -3% -10% -1% 28% -9% -1% -2% -12% -1% VA 10% 5% -6% -1% 0% -11% 7% -3% -13% 13% 18% -10% -1% -2% -13% -1% WV 5% 3% -5% -3% -2% -8% -1% -5% -11% -2% 21% -9% -2% -4% -12% -2% VISTAS 8% 7% -1% 4% 1% -5% 4% -2% -7% 3% 26% -4% 1% 0% -8% 1% 

VOC NOx CO SO2 PM-10 PVOC NOx CO SO2 PM-10 PVOC NOx CO SO2 PM-10 PVOC NOx CO SO2 PM-10 P
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Appendix F 

234

Annual Onroad Emissions Comparison

0

100,000200,000300,000400,000500,000600,000

AL FL GA KY MS NC SC TN 

Annual VOC Emissions (Tons)
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Appendix F 

235

Annual Onroad Emissions Comparison

0

500

1,0001,5002,0002,5003,0003,5004,0004,5005,000

AL FL GA KY MS NC SC TN 

Thousands

Annual CO Emissions (Tons)
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Appendix F 

236

Annual Onroad Emissions Comparison

0

50,000

100,000150,000200,000250,000300,000350,000400,000450,000500,000

AL FL GA KY MS NC SC TN 

Annual NOx Emissions (Tons)
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Appendix F 

237

Annual Onroad Emissions Comparison

0

5,000

10,00015,00020,00025,000

AL FL GA KY MS NC SC TN 

Annual SO2 Emissions (Tons)
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Appendix F 

238

Annual Onroad Emissions Comparison

0

2,0004,0006,0008,000

10,00012,000

AL FL GA KY MS NC SC TN 

Annual PM-10 Emissions (Tons)
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Appendix F 

239

Annual Onroad Emissions Comparison

0

1,0002,0003,0004,0005,0006,0007,0008,0009,000

AL FL GA KY MS NC SC TN 

Annual PM-2.5 Emissions (Tons)
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Appendix F 

240

Annual Onroad Emissions Comparison

0

5,000

10,00015,00020,00025,000

AL FL GA KY MS NC SC TN 

Annual NH3 Emissions (Tons)
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Appendix G 241

APPENDIX G: 

CONVERSION OF MRPO BaseM 

POINT SOURCE DATA 

TO SMOKE INPUT FORMAT 
Atmospheric Sciences Group 

Alpine Geophysics, LLC -- 387 Pollard Mine Road -- Burnsville, NC 28714 -- (828) 675-9045 

MEMORANDUM 

To: Pat Brewer, VISTAS 

From: Gregory Stella, Alpine Geophysics, LLC 

Re: Conversion of MRPO BaseM Point Source Data to SMOKE Input Format 

Date: 13 February 2008 

The Midwest Regional Planning Organization (MRPO) periodically produces a five State emission inventory for 

Illinois, Indiana, Michigan, Wisconsin, and Ohio. These data are used as the basis for various MRPO modeling and 

regulatory analyses. These data are prepared with the help of each State’s emission inventory divisions and are felt 

to be the most representative account for emissions activities for those States at any one time. 

The most recent version prepared and distributed by MRPO is currently called BaseM. Associated with this 2005 

base year inventory release is a set of growth and control factors that are used to additionally simulate future year 

conditions under “On-The-Books” (base case or known control programs requirements to be implemented in future 

years) or incremental control situations to test sensitivity or strategies which would be implemented in whole or in 

part during the same future years. 

The purpose of this document is to detail the technical steps that were made as part of the conversion of the MRPO 

BaseM point sources files (electric generating unit [EGU] and non-EGU) into IDA format for ASIP PM-2.5 CAMx 

modeling of the future year 2009. Because of the timing and complications relative to converting multiple and 

various emission files for all source types, it was determined that only point source emissions would be converted 

for processing at this time. 

Data Sources and Description

A series of data files and associated documentation was obtained from MRPO staff in 2007. These files were the 

input data sets for base year 2005 and growth and control factors related to MRPO’s BaseM and Round 5 

inventories6

. Because of the emission processing tools that MRPO currently executes for its analyses, these files are 

in formats that are not read by the SMOKE emissions processor currently in use by VISTAS/ASIP modelers 

(contract teams and participating states). Alpine Geophysics, under the Emissions Inventory Technical Advisor 

contract, was asked to obtain and convert these data into the formats that could be used by these modeling agencies. 

Through additional contact with MRPO staff, the base year 2005 non-EGU point source files and associated growth 

and control factors necessary to forecast the data to 2009 base case conditions were identified and extracted from the 

originally provided data. EGU sources were identified to be already prepared for the future year (2010 substituted 

for 2009) and were based on recent IPM 3.0 model runs with incremental adjustment made by MRPO states to best 

reflect expected emission controls and operating conditions. The “will do” simulation series for EGUs was identified 

as “egu5b_2010.” 

The main purpose of the SMOKE conversion task was to prepare five state emission inventories provided in 

National Input Format (NIF) format into the IDA format required by the SMOKE model for the criteria pollutants 

VOC, NOx, CO, SO2, PM-10, PM-2.5, and NH3. Annual emissions were taken directly from the NIF structured 

inventories with no alternate temporal calculations performed (e.g., estimate seasonal emissions from annual or 

annual from seasonal). The temporal allocation module of the SMOKE emissions processor was intended to be used 

to further define temporal distribution of these emissions. 

 

6

 http://www.ladco.org/tech/emis/r5/round5_reports.htm 
Atmospheric Sciences Group 

Alpine Geophysics, LLC -- 387 Pollard Mine Road -- Burnsville, NC 28714 -- (828) 675-9045 

No quality assurance (QA) related to the reported values in the MRPO was conducted (e.g., it was assumed that 

reported emission levels were correct) and therefore the QA focus of these tasks was to maintain the integrity of the 

mass files in the conversion to IDA. 

Each set of NIF structured data had a unique set of relational tables necessary to maintain the information required 

in each source sector based on its reporting requirements. Alpine had previously developed scripts to read the 

information from each of these relational data sets and convert them to the IDA structures required by this task. 

Prior to and after each major source sector was converted from NIF to IDA, we developed a list of emission 

summary reports to check that the emissions input into the conversion process were the same as output into the IDA 

formatted files. 

Non-EGU Point Source Conversion 

Non-EGU point source emissions from 2005 BaseM were converted to future year 2009 IDA format using the 

annual emission records directly from the NIF structured data sets and associated SCC growth factors and unit, 

facility, county, state, or nationally applied controls7

. These controls were applied in a hierarchical fashion starting 

with the most defined (unit-segment-pollutant level) through least defined (national-SCC-pollutant) and when a 

match was found during the implementation, no additional controls were sought or applied to that emission record. 

In other words, if a match were found at the unit-segment level of control, no additional controls were applied to that 

segment/pollutant combination again in the forecast process. This prevented multiple control programs from being 

implemented when the intent of the originally provided control files were to assign a single applicable reduction. 

The Round 5 factors for point sources provided by MRPO were in the RPO Data Exchange Format (RPODx) and 

had growth and control factors available at the State, county, plant, unit, segment, stack, and SCC level of detail. In 

order to apply these factors in a fashion consistent with that of the MRPO utilized processing system and duplicative 

of how MRPO would have generated its BaseM forecasts, a hierarchical approach was utilized to match and assign 

growth and control values. 

Growth Factor Application 

Using the 2005 EM table from the BaseM inventory files in NIF format, we first selected each emissions record for 

forecasting. In this conversion case, these EM records were limited to those emissions identified as annual using the 

NIF coding convention. As noted in the limitations section below, there oftentimes were emissions provided by 

MRPO in a summer season convention. 

We next selected the base year for application as the RPODx for growth rates allows for the flexibility of input 

growth factors for multiple base year inventories. In this assignment, the base year was always 2005, as that was the 

base year provided by MRPO and the future year was 2009, as selected by ASIP. 

The next step was to determine the growth basis for each individual emission record of the file. This “growth basis” 

is the key with which the growth factor is associated. For point sources, this key is based on a combination of FIPS, 

SCC, and pollutant codes. Multiple keys are calculated for each individual emission record and that key with the 

highest resolution of matching to the growth factor file using the hierarchy identified in Table 1 below is the one 

chosen to assign a growth rate to the base year emissions. 

 

7

http://www.ladco.org/tech/emis/r5/reports/LADCO%202005%20Base%20Yr%20Growth%20and%20Controls%20

Report_Final.pdf 
Atmospheric Sciences Group 

Alpine Geophysics, LLC -- 387 Pollard Mine Road -- Burnsville, NC 28714 -- (828) 675-9045 

Table 1. Point Source Growth Factor Application Hierarchy.

Order Key or “Growth/Control Basis” 

1 state/county code, 10-digit SCC, pollutant 

2 state/county code, 10-digit SCC 

3 state code, 10-digit SCC, pollutant 

4 state code, 10-digit SCC 

5 state/county code, pollutant 

6 state/county code 

7 state code, pollutant 

8 state code 

9 10-digit SCC, pollutant 

10 10-digit SCC 

11 Pollutant 

Using the hierarchical application, growth basis, and dates (base year and alternate year), we matched each emission 

record to the growth table to obtain a growth factor. The factors are defined in the growth table as a multiplier for 

the base year period that calculates the alternate year of interest. In other words, multiplying the base year emissions 

value by the growth factor provides you with the emissions for the alternate year of interest. 

When no match from any of the hierarchical keys was identified, a growth rate of 1.00 (no growth) was assigned. 

This maintained the 2005 emission level in the future year inventory. 

Control Factor Application 

Similar to the process identified above for the assignment and application of growth factors, the control factor 

assignment was based on a hierarchical key, this time, however, using FIPS, plantid, pointid, stackid, segment, SCC, 

and pollutant codes applied in a parallel process to the growth factor assignment. 

Using the 2005 EM table from the BaseM inventory files in NIF format, we selected each annual emissions record 

for forecasting. We next selected the base year for application, and again, the base year was always 2005, as that 

was the base year provided by MRPO. 

Once the base year was identified, we determined the alternate year for our forecast. Depending on the specific year 

used in each conversion, growth rates were limited to those with a base year of 2005 and a future year less than or 

equal to that of our forecast. This variation in method is intended to allow us to identify all controls implemented 

prior to or during the year of interest and will consider them as viable options at the latest provided level of control. 

In other words, since we selected 2009 as the future year of choice, we limit the control factor table to control 

strategies implemented during or prior to 2009. If in our matching to the control factor table we find that for a 

certain control basis key there is no match because a program may have been fully implemented in a prior year (say 

2007), then we do not want to exclude this reduction from our forecast. Additionally, if we find that there are 

multiple entries in the control factor table because of incremental implementation of a rule, we select the closest year 

to that of our intended forecast. So if a particular rule was incrementally implemented from 2005 through 2009 and 

there were control records available for each year in between, we would select the record with the latest year to 

apply in our forecast. 

The next step was to determine the control basis for each individual emission record of the file. This “control basis” 

is the key with which the control strategy or technology is associated. Although we developed code to support the 

hierarchical application of control factors for the BaseM emissions, all control factors provided by MRPO in the 

Round 5 files were segment-SCC-pollutant specific. This eliminated the need for a search on the key that has the 

greatest resolution as all matches were at the segment-SCC-pollutant level. 
Atmospheric Sciences Group 

Alpine Geophysics, LLC -- 387 Pollard Mine Road -- Burnsville, NC 28714 -- (828) 675-9045 

Using the control basis and dates (base year and alternate year), we matched each emission record to the control 

table to obtain a control factor. The factors are defined in the control table as a group of values (control efficiency, 

rule effectiveness, and rule penetration) for the future year period that gets assigned to an uncontrolled future year 

emission value. In other words, we first “backed out” existing base year controls from our future year emissions 

estimate and then multiplied this uncontrolled value by the control factors for the alternate year of interest. These 

calculations are defined in Equations 1 and 2 below. 

Equation 1. Uncontrolled emissions calculation. 

Emiss Unc= Emiss Base / (1-((CE Base /100)*(RE Base /100)*(RP Base /100))) 

Where, 

Emiss Unc = Uncontrolled emissions 

Emiss Base = Base year emissions 

CE Base = Base year control efficiency 

RE Base = Base year rule effectiveness 

RP Base = Base year rule penetration 

Equation 2. Application of new control calculation. 

Emiss New = Emiss Unc *(1-((CE New /100)*(RE New /100)*(RP New /100))) 

Where, 

Emiss New = Future year emissions 

Emiss Unc = Uncontrolled emissions 

CE New = Future year control efficiency 

RE New = Future year rule effectiveness 

RP New = Future year rule penetration 

When no match from any of the hierarchical keys was identified, the same control efficiency, rule efficiency, and 

rule penetration values from the base year inventory were used in the calculation and the only change in emissions 

would have been the result of growth factor application. In instances where PM-10 annual emissions were found to 

be less than PM-2.5 annual emission values, the PM-2.5 emission values were changed to equal that of PM-10. 

EGU Point Source Conversion 

EGU point source emissions from the egu5b_2010 scenario (2010 IPM 3.0 run with modifications) were converted 

to year 2009 IDA format using the annual emission records directly from the NIF structured data sets. Since these 

emissions already accounted for growth and control application, no additional modifications were required. 

One ASIP requested modification for its PM-2.5 CAMx modeling was to adjust the 2009 file to match W. H. 

Sammis facility’s planned response to the control requirements from the consent decree USA vs. Ohio Edison; Civil 

Action No: 2:99-CV-1181; March 18, 2005. These changes were not implemented in the ASIP 2009 CMAQ runs. 

These adjustments for SO2 are noted in Table 2 below. 
Atmospheric Sciences Group 

Alpine Geophysics, LLC -- 387 Pollard Mine Road -- Burnsville, NC 28714 -- (828) 675-9045 

Table 2. SO2 Control Requirements from USA vs. Ohio Edison Consent Decree 

Units 1-4 Induct Scrubbing 

 50% removal (1.1 lbs/MMBtu) 

 At least one unit by Sept. 30, 2008 

 Second unit by Dec. 31, 2008 

 Other two units by Dec. 31, 2009 

 

Unit 5 Flash Dryer Absorber or Electro-Catalytic Oxidation no later than Dec. 31, 2008 

 50% removal (1.1 lbs/MMBtu) 

 

Units 6/7 Scrubber no later than December 31, 2010 

 95% removal (0.13 lbs/MMBtu) 

 

Plantwide Emission cap of 101,500 by end of 2009 

 Emission cap of 101,500 by end of 2010 

 Emission cap of 29,900 by end of 2011 

Conversion Limitations

As noted above, Alpine limited our conversion to all records in the MRPO point source files that were identified as 

annual. In some cases the MRPO NIF files had additional non-annual summer season emission records configured 

as a higher percentage than the annual average that was used in our emissions comparison. 

In other words, the MRPO file sometimes had two emission record types that it uses for its modeling; one for the 

summer period and one for the rest of the year. Since SMOKE uses temporal allocation factors to make this 

summer/winter split, our converted values do not match MRPO's summertime reports. We see a high percentage 

difference in the Alpine converted data compared to the MRPO output reports in these two States for the July 12 

example for this reason. 

Since we confirmed this difference and reason for this difference in the 2005 data sets with MRPO, our objective for 

QA on the projections also included delta emissions from the projection year to the base year. Although the absolute 

daily emission values (in tpd) were found to be different as noted above, in all cases, the difference between 2005 

and the projection year calculations as made by Alpine was within confidence ranges of the ratio of future year to 

base year as posted by MRPO. See Table 3 below. For this reason, we were convinced that our projection 

methodology is capturing the growth and control factors that MRPO applied in its emissions modeling.
Atmospheric Sciences Group 

Appendix G 247Table 3. Emissions Comparison of ASIP Converted and MRPO Non-EGU Emissions. 

Comparison of ASIP Converted and MRPO Non-EGU EmissionsFIPSST State VOC NOX CO SO2 PM-10 PM-2.5 NH317 Illinois 61,760 85,142 71,725 150,506 20,315 6,256 1,05918 Indiana 48,287 65,132 339,642 82,040 22,118 12,774 78226 Michigan 36,753 85,014 67,564 55,435 13,235 6,567 78839 Ohio 31,530 67,275 212,626 116,942 15,930 10,443 3,23955 Wisconsin 31,377 36,827 43,014 60,955 456 43 346

MRPO 209,707 339,390 734,570 465,878 72,054 36,082 6,214

FIPSST State VOC NOX CO SO2 PM-10 PM-2.5 NH3 FIPSST State VOC NOX CO 17 Illinois 222.3 315.1 250.9 412.3 55.6 17.1 2.9 17 Illinois 218.1 217.8 255.7 318 Indiana 132.3 178.4 930.5 224.8 60.6 35.0 2.1 18 Indiana 137.2 175.2 888.8 226 Michigan 115.8 232.4 193.6 144.9 40.8 19.3 2.4 26 Michigan 119.1 242.0 206.5 139 Ohio 86.4 184.3 582.5 320.4 43.6 28.6 8.9 39 Ohio 87.1 166.3 540.7 255 Wisconsin 86.0 100.9 117.8 167.0 1.3 0.1 0.9 55 Wisconsin 87.7 92.9 120.0 1

MRPO 642.7 1,011.1 2,075.4 1,269.4 202.0 100.2 17.2 MRPO 649.2 894.2 2,011.7 1,1

FIPSST State VOC NOX CO SO2 PM-10 PM-2.5 NH3 FIPSST State VOC NOX CO 17 Illinois 29.5% 25.1% 9.8% 32.3% 28.2% 17.3% 17.0% 17 Illinois 33.6% 24.4% 12.7% 2918 Indiana 23.0% 19.2% 46.2% 17.6% 30.7% 35.4% 12.6% 18 Indiana 21.1% 19.6% 44.2% 1926 Michigan 17.5% 25.0% 9.2% 11.9% 18.4% 18.2% 12.7% 26 Michigan 18.3% 27.1% 10.3% 1339 Ohio 15.0% 19.8% 28.9% 25.1% 22.1% 28.9% 52.1% 39 Ohio 13.4% 18.6% 26.9% 2555 Wisconsin 15.0% 10.9% 5.9% 13.1% 0.6% 0.1% 5.6% 55 Wisconsin 13.5% 10.4% 6.0% 13

MRPO 100% 100% 100% 100% 100% 100% 100% MRPO 100.0% 100.0% 100.0% 100

ASIP 2009 July 12 Summer Daily Emissions (% of MRPO Total) 2009 July 12 Summer Daily Em

ASIP 2009 Annual Emissions (Tons/Year)

ASIP 2009 July 12 Summer Daily Emissions (Tons/Day) 2009 July 12 Summer Dail
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 248

APPENDIX H: 

COMPARISON OF EGU CONTROLS FOR COAL AND OIL/GAS UNITS 

BASED ON IPM MODELING AND STATE-PROVIDED INFORMATION 

FOR THE BASE G/G2 INVENTORY
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

249

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

01033 TVA COLBERT 47 1 0010 010 Coal Steam None None SCR SCR None 01033 TVA COLBERT 47 2 0010 011 Coal Steam None None SCR SCR None 01033 TVA COLBERT 47 3 0010 012 Coal Steam None None SCR SCR None 01033 TVA COLBERT 47 4 0010 013 Coal Steam None None SCR SCR None 01033 TVA COLBERT 47 5 0010 014 Coal Steam SCR SCR SCR SCR Scrubber 01055 ALABAMA POWER COMPANY GADSDEN 7 1 0002 002 Coal Steam None None None None None 01055 ALABAMA POWER COMPANY GADSDEN 7 2 0002 003 Coal Steam None None None None None 01063 ALABAMA POWER COMPANY GREENE COUNTY 10 1 0001 002 Coal Steam SCR SCR SCR SCR None 01063 ALABAMA POWER COMPANY GREENE COUNTY 10 2 0001 003 Coal Steam SCR SCR SCR SCR None 01071 TVA - WIDOWS CREEK 50 1 0008 002 Coal Steam SCR SCR SCR SCR None 01071 TVA - WIDOWS CREEK 50 2 0008 003 Coal Steam SCR SCR SCR SCR None 01071 TVA - WIDOWS CREEK 50 3 0008 004 Coal Steam SCR SCR SCR SCR None 01071 TVA - WIDOWS CREEK 50 4 0008 005 Coal Steam SCR SCR SCR SCR None 01071 TVA - WIDOWS CREEK 50 5 0008 006 Coal Steam SCR SCR SCR SCR None 01071 TVA - WIDOWS CREEK 50 6 0008 007 Coal Steam SCR SCR SCR SCR None 01071 TVA - WIDOWS CREEK 50 7 0008 008 Coal Steam SCR SCR SCR SCR Scrubber 01071 TVA - WIDOWS CREEK 50 8 0008 009 Coal Steam SCR SCR SCR SCR Scrubber 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

250

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

01073 ALABAMA POWER COMPANY (MILLER POWER PLANT) 6002 4 010730011 001 Coal Steam SCR All Year SCR Summer SCR All Year SCR Summer None 01073 ALABAMA POWER COMPANY (MILLER POWER PLANT) 6002 3 010730011 002 Coal Steam SCR All Year SCR Summer SCR All Year SCR Summer None 01073 ALABAMA POWER COMPANY (MILLER POWER PLANT) 6002 2 010730011 004 Coal Steam SCR All Year SCR Summer SCR All Year SCR Summer None 01073 ALABAMA POWER COMPANY (MILLER POWER PLANT) 6002 1 010730011 005 Coal Steam SCR All Year SCR Summer SCR All Year SCR Summer None 01097 ALABAMA POWER COMPANY BARRY 3 1 1001 002 Coal Steam SNCR None SNCR SCR None 01097 ALABAMA POWER COMPANY BARRY 3 2 1001 003 Coal Steam SNCR None SNCR SCR None 01097 ALABAMA POWER COMPANY BARRY 3 3 1001 004 Coal Steam SNCR None SNCR SCR None 01097 ALABAMA POWER COMPANY BARRY 3 4 1001 005 Coal Steam SNCR None SNCR SCR None 01097 ALABAMA POWER COMPANY BARRY 3 5 1001 006 Coal Steam None None SCR SCR None 01117 ALABAMA POWER COMPANY E C GASTON 26 1 0005 002 Coal Steam None SCR None SCR None 01117 ALABAMA POWER COMPANY E C GASTON 26 2 0005 003 Coal Steam None SCR None SCR None 01117 ALABAMA POWER COMPANY E C GASTON 26 3 0005 004 Coal Steam None SCR None SCR None 01117 ALABAMA POWER COMPANY E C GASTON 26 4 0005 005 Coal Steam None SCR None SCR None 01117 ALABAMA POWER COMPANY E C GASTON 26 5 0005 006 Coal Steam SCR SCR SCR SCR None 01127 ALABAMA POWER COMPANY GORGAS 8 6 0001 004 Coal Steam None None None None None 01127 ALABAMA POWER COMPANY GORGAS 8 7 0001 005 Coal Steam None None None None None 01127 ALABAMA POWER COMPANY GORGAS 8 8 0001 006 Coal Steam None None None None Scrubber 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

251

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

01127 ALABAMA POWER COMPANY GORGAS 8 9 0001 007 Coal Steam None None None None Scrubber 01127 ALABAMA POWER COMPANY GORGAS 8 10 0001 008 Coal Steam SCR SCR SCR SCR Scrubber 01129 ALABAMA ELECTRIC COOP CHARLES R LOWMAN 56 1 0001 002 Coal Steam None None None None Scrubber 01129 ALABAMA ELECTRIC COOP CHARLES R LOWMAN 56 2 0001 003 Coal Steam SCR SCR SCR SCR Scrubber 01129 ALABAMA ELECTRIC COOP CHARLES R LOWMAN 56 3 0001 004 Coal Steam SCR SCR SCR SCR Scrubber 12001 GAINESVILLE REGIONAL UTILITIES JOHN R KELLY 664 JRK6 O/G Steam O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement 12001 GAINESVILLE REGIONAL UTILITIES JOHN R KELLY 664 JRK7 O/G Steam O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement 12001 GAINESVILLE REGIONAL UTILITIES JOHN R KELLY 664 JRK8 0010005 7 O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement 12001 CITY OF GAINESVILLE, GRU DEERHAVEN 663 B1 0010006 3 O/G Steam No Operation No Operation No Operation No Operation No Operation 12001 CITY OF GAINESVILLE, GRU DEERHAVEN 663 B2 0010006 5 Coal Steam None None SCR SCR None 12005 GULF POWER COMPANY LANSING SMITH PLANT 643 1 0050014 1 Coal Steam None None SCR SCR None 12005 GULF POWER COMPANY LANSING SMITH PLANT 643 2 0050014 2 Coal Steam None None SCR SCR None 12009 FLORIDA POWER & LIGHT (PCC) CAPE CANAVERAL 609 PCC1 0090006 1 O/G Steam No Operation No Operation No Operation No Operation No Operation 12009 FLORIDA POWER & LIGHT (PCC) CAPE CANAVERAL 609 PCC2 0090006 2 O/G Steam No Operation No Operation No Operation No Operation No Operation 12011 FLORIDA POWER & LIGHT (PPE) PORT EVERGLADES 617 PPE1 0110036 1 O/G Steam No Operation No Operation No Operation No Operation No Operation 12011 FLORIDA POWER & LIGHT (PPE) PORT EVERGLADES 617 PPE2 0110036 2 O/G Steam None None None None None 12011 FLORIDA POWER & LIGHT (PPE) PORT EVERGLADES 617 PPE3 0110036 3 O/G Steam None None None None None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

252

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

12011 FLORIDA POWER & LIGHT (PPE) PORT EVERGLADES 617 PPE4 0110036 4 O/G Steam None None None None None 12017 PROGRESS ENERGY FLORIDA CRYSTAL RIVER 628 1 0170004 1 Coal Steam None None None None None 12017 PROGRESS ENERGY FLORIDA CRYSTAL RIVER 628 2 0170004 2 Coal Steam None None None None None 12017 PROGRESS ENERGY FLORIDA CRYSTAL RIVER 628 5 0170004 3 Coal Steam None None SCR SCR None 12017 PROGRESS ENERGY FLORIDA CRYSTAL RIVER 628 4 0170004 4 Coal Steam SCR SCR SCR SCR Scrubber 12031 SAINT JOHNS RIVER 207 1 0310045-A 16 SCR SCR SCR SCR Scrubber 12031 SAINT JOHNS RIVER 207 2 0310045-A 17 SCR SCR SCR SCR Scrubber 12031 NORTHSIDE 667 2A 0310045-B 26 O/G Steam No Operation No Operation None No Operation No Operation 12031 NORTHSIDE 667 1A 0310045-B 27 O/G Steam No Operation No Operation None No Operation No Operation 12031 NORTHSIDE 667 3 0310045-B 3 O/G Steam None None None No Operation None 12031 CEDAR BAY COGENERATION INC. 10672 GEN1 0310337 1 Coal Steam None SNCR None SNCR Scrubber 12031 CEDAR BAY COGENERATION INC. 0310337 2 12031 CEDAR BAY COGENERATION INC. 0310337 3 12033 GULF POWER COMPANY CRIST ELECTRIC GENERATION 641 1 0330045 1 12033 GULF POWER COMPANY CRIST ELECTRIC GENERATION 641 2 0330045 2 O/G Steam O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement 12033 GULF POWER COMPANY CRIST ELECTRIC GENERATION 641 3 0330045 3 O/G Steam O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement 12033 GULF POWER COMPANY CRIST ELECTRIC GENERATION 641 4 0330045 4 Coal Steam None None None None None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

253

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

12033 GULF POWER COMPANY CRIST ELECTRIC GENERATION 641 5 0330045 5 Coal Steam None None None None None 12033 GULF POWER COMPANY CRIST ELECTRIC GENERATION 641 6 0330045 6 Coal Steam SNCR SNCR SNCR SNCR None 12033 GULF POWER COMPANY CRIST ELECTRIC GENERATION 641 7 0330045 7 Coal Steam SCR SCR SCR SCR None 12053 Central Power and Lime Incorporated 10333 GEN1 0530021 18 Coal Steam None None None None Scrubber 12057 TAMPA ELECTRIC COMPANY BIG BEND STATION 645 BB01 0570039 1 Coal Steam SCR SCR SCR SCR Scrubber 12057 TAMPA ELECTRIC COMPANY BIG BEND STATION 645 BB02 0570039 2 Coal Steam SCR SCR SCR SCR Scrubber 12057 TAMPA ELECTRIC COMPANY BIG BEND STATION 645 BB03 0570039 3 Coal Steam SCR SCR SCR SCR Scrubber 12057 TAMPA ELECTRIC COMPANY BIG BEND STATION 645 BB04 0570039 4 Coal Steam SCR SCR SCR SCR Scrubber 12057 TAMPA ELECTRIC COMPANY F.J. GANNON STATION 646 GB01 0570040 1 No Operation No Operation No Operation No Operation No Operation 12057 TAMPA ELECTRIC COMPANY F.J. GANNON STATION 646 GB02 0570040 2 No Operation No Operation No Operation No Operation No Operation 12057 TAMPA ELECTRIC COMPANY F.J. GANNON STATION 646 GB03 0570040 3 No Operation No Operation No Operation No Operation No Operation 12057 TAMPA ELECTRIC COMPANY F.J. GANNON STATION 646 GB04 0570040 4 No Operation No Operation No Operation No Operation No Operation 12057 TAMPA ELECTRIC COMPANY F.J. GANNON STATION 646 GB05 0570040 5 No Operation No Operation No Operation No Operation No Operation 12057 TAMPA ELECTRIC COMPANY F.J. GANNON STATION 646 GB06 0570040 6 No Operation No Operation No Operation No Operation No Operation 12061 CITY OF VERO BEACH 693 0610029 1 O/G Steam O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement 12061 CITY OF VERO BEACH 693 3 0610029 3 O/G Steam No Operation No Operation No Operation No Operation No Operation 12061 CITY OF VERO BEACH 693 4 0610029 4 O/G Steam No Operation No Operation No Operation No Operation No Operation 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

254

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

12063 GULF POWER COMPANY SCHOLZ 642 1 0630014 1 Coal Steam None None None None None 12063 GULF POWER COMPANY SCHOLZ 642 2 0630014 2 Coal Steam None None None None None 12073 CITY OF TALLAHASSEE ARVAH B.HOPKINS 688 1 0730003 1 O/G Steam No Operation No Operation No Operation No Operation No Operation 12073 CITY OF TALLAHASSEE ARVAH B.HOPKINS 688 2 0730003 4 O/G Steam No Operation No Operation No Operation No Operation No Operation 12081 FLORIDA POWER & LIGHT (PMT) MANATEE POWER 6042 PMT1 0810010 1 O/G Steam No Operation No Operation No Operation No Operation No Operation 12081 FLORIDA POWER & LIGHT (PMT) MANATEE POWER 6042 PMT2 0810010 2 O/G Steam No Operation No Operation No Operation No Operation No Operation 12085 FLORIDA POWER & LIGHT (PMR) FPL / MARTIN 6043 PMR1 0850001 1 O/G Steam None None No Operation No Operation None 12085 FLORIDA POWER & LIGHT (PMR) FPL / MARTIN 6043 PMR2 0850001 2 O/G Steam None None No Operation No Operation None 12085 INDIANTOWN COGENERATION, L.P. 50976 GEN1 0850102 1 Coal Steam SCR SCR SCR SCR Scrubber 12086 FLORIDA POWER & LIGHT (PCU) CUTLER POWER 610 PCU5 0250001 3 O/G Steam No Operation No Operation No Operation No Operation No Operation 12086 FLORIDA POWER & LIGHT (PCU) CUTLER POWER 610 PCU6 0250001 4 O/G Steam No Operation No Operation No Operation No Operation No Operation 12086 FLORIDA POWER & LIGHT (PTF) TURKEY POINT 621 PTP1 0250003 1 O/G Steam None None No Operation No Operation None 12086 FLORIDA POWER & LIGHT (PTF) TURKEY POINT 621 PTP2 0250003 2 O/G Steam None None No Operation No Operation None 12095 

ORLANDO UTILITIES COMMISSION STANTON ENERGY 

564 1 0950137 1 Coal Steam SCR SCR SCR SCR Scrubber 

12095 

ORLANDO UTILITIES COMMISSION STANTON ENERGY 

564 2 0950137 2 Coal Steam SCR SCR SCR SCR Scrubber 

12099 FLORIDA POWER & LIGHT (PRV) RIVIERA POWE 619 PRV3 0990042 3 O/G Steam No Operation No Operation No Operation No Operation No Operation 12099 FLORIDA POWER & LIGHT (PRV) RIVIERA POWE 619 PRV4 0990042 4 O/G Steam No Operation No Operation No Operation No Operation No Operation 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

255

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

12099 

CITY OF LAKE WORTH UTILITIES TOM G. SMITH 

673 S-1 0990045 7 O/G Steam O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement 

12099 

CITY OF LAKE WORTH UTILITIES TOM G. SMITH 

673 S-3 0990045 9 O/G Steam O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement 

12101 PROGRESS ENERGY FLORIDA ANCLOTE 8048 1 1010017 1 O/G Steam None None No Operation No Operation None 12101 PROGRESS ENERGY FLORIDA ANCLOTE 8048 2 1010017 2 O/G Steam None None No Operation No Operation None 12103 PROGRESS ENERGY FLORIDA BARTOW 634 1 1030011 1 O/G Steam No Operation No Operation None No Operation No Operation 12103 PROGRESS ENERGY FLORIDA BARTOW 634 2 1030011 2 O/G Steam O/G Early Retirement O/G Early Retirement None O/G Early Retirement O/G Early Retirement 12103 PROGRESS ENERGY FLORIDA BARTOW 634 3 1030011 3 O/G Steam No Operation No Operation None No Operation No Operation 12105 LAKELAND ELECTRIC CHARLES LARSEN 675 7 1050003 4 O/G Steam O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement 12105 LAKELAND ELECTRIC C.D. MCINTOSH, JR. 676 3 1050004 6 Coal Steam SCR SCR SCR SCR Scrubber 12107 SEMINOLE ELECTRIC COOPERATIVE, INC. 136 1 1070025 1 Coal Steam SCR SCR SCR SCR Scrubber 12107 SEMINOLE ELECTRIC COOPERATIVE, INC. 136 2 1070025 2 Coal Steam SCR SCR SCR SCR Scrubber 12111 FT PIERCE UTILITIES AUTHORITY FT PIERCE 658 7 1110003 7 O/G Steam No Operation No Operation No Operation No Operation No Operation 12111 FT PIERCE UTILITIES AUTHORITY FT PIERCE 658 8 1110003 8 O/G Steam No Operation No Operation No Operation No Operation No Operation 12121 PROGRESS ENERGY FLORIDA SUWANNEE RIVER 638 1 1210003 1 O/G Steam O/G Early Retirement O/G Early Retirement None O/G Early Retirement O/G Early Retirement 12121 PROGRESS ENERGY FLORIDA SUWANNEE RIVER 638 2 1210003 2 O/G Steam O/G Early Retirement O/G Early Retirement None O/G Early Retirement O/G Early Retirement 12121 PROGRESS ENERGY FLORIDA SUWANNEE RIVER 638 3 1210003 3 O/G Steam No Operation No Operation None No Operation No Operation 12127 FLORIDA POWER & LIGHT (PSN) SANFORD POWER 620 PSN3 1270009 1 O/G Steam O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

256

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

12127 FLORIDA POWER & LIGHT (PSN) SANFORD POWER 620 PSN4 1270009 2 No Operation No Operation No Operation No Operation No Operation 12129 

TALLAHASSEE CITY PURDOM GENERATING STATION 

689 7 1290001 7 O/G Steam No Operation No Operation No Operation No Operation No Operation 

13015 GEORGIA POWER COMPANY, BOWEN STEAM-ELECT 703 1BLR 01500011 SG01 Coal Steam SCR SCR SCR SCR None 13015 GEORGIA POWER COMPANY, BOWEN STEAM-ELECT 703 2BLR 01500011 SG02 Coal Steam SCR SCR SCR SCR None 13015 GEORGIA POWER COMPANY, BOWEN STEAM-ELECT 703 3BLR 01500011 SG03 Coal Steam SCR SCR SCR SCR Scrubber 13015 GEORGIA POWER COMPANY, BOWEN STEAM-ELECT 703 4BLR 01500011 SG04 Coal Steam SCR SCR SCR SCR Scrubber 13021 ARKWRIGHT 699 1 0002 1 No Operation No Operation No Operation No Operation No Operation 13021 ARKWRIGHT 699 2 0002 2 No Operation No Operation No Operation No Operation No Operation 13021 ARKWRIGHT 699 3 0002 3 No Operation No Operation No Operation No Operation No Operation 13021 ARKWRIGHT 699 4 0002 4 No Operation No Operation No Operation No Operation No Operation 13051 SAVANNAH ELECTRIC: KRAFT STEAM 733 1 05100006 SG01 Coal Steam None None None None None 13051 SAVANNAH ELECTRIC: KRAFT STEAM 733 2 05100006 SG02 Coal Steam None None None None None 13051 SAVANNAH ELECTRIC: KRAFT STEAM 733 3 05100006 SG03 Coal Steam None None None SCR None 13051 SAVANNAH ELECTRIC: KRAFT STEAM 733 4 05100006 SG04 O/G Steam No Operation No Operation No Operation No Operation No Operation 13051 RIVERSIDE 734 11 05100018 11 O/G Steam None No Operation No Operation No Operation None 13051 RIVERSIDE 734 12 05100018 12 O/G Steam None No Operation No Operation No Operation None 13051 RIVERSIDE 734 4 05100018 4 O/G Steam None None None None None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

257

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

13051 RIVERSIDE 734 5 05100018 5 O/G Steam None No Operation No Operation No Operation None 13051 RIVERSIDE 734 6 05100018 6 O/G Steam None No Operation No Operation No Operation None 13067 GEORGIA POWER COMPANY, MCDONOUGH STEAM 710 MB1 06700003 SGM1 Coal Steam None None SCR SCR None 13067 GEORGIA POWER COMPANY, MCDONOUGH STEAM 710 MB2 06700003 SGM2 Coal Steam None None SCR SCR None 13077 GEORGIA POWER COMPANY, YATES STEAM-ELECTRIC 728 Y1BR 07700001 SG01 Coal Steam None None None None Scrubber 13077 GEORGIA POWER COMPANY, YATES STEAM-ELECTRIC 728 Y2BR 07700001 SG02 Coal Steam None None None None None 13077 GEORGIA POWER COMPANY, YATES STEAM-ELECTRIC 728 Y3BR 07700001 SG03 Coal Steam None None None None None 13077 GEORGIA POWER COMPANY, YATES STEAM-ELECTRIC 728 Y4BR 07700001 SG04 Coal Steam None None SCR SCR None 13077 GEORGIA POWER COMPANY, YATES STEAM-ELECTRIC 728 Y5BR 07700001 SG05 Coal Steam None None SCR SCR None 13077 GEORGIA POWER COMPANY, YATES STEAM-ELECTRIC 728 Y6BR 07700001 SG06 Coal Steam None None SCR SCR None 13077 GEORGIA POWER COMPANY, YATES STEAM-ELECTRIC 728 Y7BR 07700001 SG07 Coal Steam None None SCR SCR None 13095 GEORGIA POWER COMPANY, MITCHELL STEAM-ELECTRIC 727 09500002 SG01 No Operation No Operation No Operation No Operation No Operation 13095 GEORGIA POWER COMPANY, MITCHELL STEAM-ELECTRIC 727 09500002 SG02 No Operation No Operation No Operation No Operation No Operation 13095 GEORGIA POWER COMPANY, MITCHELL STEAM-ELECTRIC 727 3 09500002 SG03 Coal Steam None None None None None 13103 SAVANNAH ELECTRIC: MCINTOSH STEAM - ELECTRIC 6124 1 10300003 SG01 Coal Steam None None None SCR None 13115 GEORGIA POWER COMPANY, HAMMOND STEAM-ELECTRIC 708 1 11500003 SG01 Coal Steam None None SCR SCR Scrubber 13115 GEORGIA POWER COMPANY, HAMMOND STEAM-ELECTRIC 708 2 11500003 SG02 Coal Steam None None SCR SCR Scrubber 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

258

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

13115 GEORGIA POWER COMPANY, HAMMOND STEAM-ELECTRIC 708 3 11500003 SG03 Coal Steam None None SCR SCR Scrubber 13115 GEORGIA POWER COMPANY, HAMMOND STEAM-ELECTRIC 708 4 11500003 SG04 Coal Steam SCR SCR SCR SCR Scrubber 13127 GEORGIA POWER COMPANY, MCMANUS STEAM-ELECTRIC 715 1 12700004 SG01 O/G Steam No Operation No Operation No Operation No Operation No Operation 13127 GEORGIA POWER COMPANY, MCMANUS STEAM-ELECTRIC 715 2 12700004 SG02 O/G Steam No Operation No Operation No Operation No Operation No Operation 13149 GEORGIA POWER COMPANY, WANSLEY STEAM-ELECTRIC 6052 1 14900001 SG01 Coal Steam SCR SCR SCR SCR Scrubber 13149 GEORGIA POWER COMPANY, WANSLEY STEAM-ELECTRIC 6052 2 14900001 SG02 Coal Steam SCR SCR SCR SCR None 13207 GEORGIA POWER COMPANY, SCHERER STEAM-ELECTRIC 6257 1 20700008 SG01 Coal Steam None None None None None 13207 GEORGIA POWER COMPANY, SCHERER STEAM-ELECTRIC 6257 2 20700008 SG02 Coal Steam None None None None None 13207 GEORGIA POWER COMPANY, SCHERER STEAM-ELECTRIC 6257 3 20700008 SG03 Coal Steam None None None None None 13207 GEORGIA POWER COMPANY, SCHERER STEAM-ELECTRIC 6257 4 20700008 SG04 Coal Steam None None None None None 13237 GEORGIA POWER COMPANY, HARLLEE BRANCH 709 1 23700008 SG01 Coal Steam None None SCR SCR None 13237 GEORGIA POWER COMPANY, HARLLEE BRANCH 709 2 23700008 SG02 Coal Steam None None SCR SCR None 13237 GEORGIA POWER COMPANY, HARLLEE BRANCH 709 3 23700008 SG03 Coal Steam None None SCR SCR None 13237 GEORGIA POWER COMPANY, HARLLEE BRANCH 709 4 23700008 SG04 Coal Steam None None SCR SCR None 21015 CINCINNATI GAS & ELECTRIC EAST BEND STAT 6018 2 2101500029 002 Coal Steam SCR SCR SCR SCR Scrubber 21041 KENTUCKY UTILITIES CO GHENT GENERATING STATION 1356 1 2104100010 001 Coal Steam SCR None SCR SCR Scrubber 21041 KENTUCKY UTILITIES CO GHENT GENERATING STATION 1356 2 2104100010 002 Coal Steam None None SCR SCR Scrubber 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

259

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

21041 KENTUCKY UTILITIES CO GHENT GENERATING STATION 1356 3 2104100010 003 Coal Steam SCR None SCR SCR Scrubber 21041 KENTUCKY UTILITIES CO GHENT GENERATING STATION 1356 4 2104100010 004 Coal Steam SCR None SCR SCR Scrubber 21049 EAST KY POWER COOP WILLIAM C DALE PLANT 1385 1 2104900003 001 Coal Steam None None None None None 21049 EAST KY POWER COOP WILLIAM C DALE PLANT 1385 2 2104900003 002 Coal Steam None None None None None 21049 EAST KY POWER COOP WILLIAM C DALE PLANT 1385 3 2104900003 003 Coal Steam None None None None None 21049 EAST KY POWER COOP WILLIAM C DALE PLANT 1385 4 2104900003 004 Coal Steam None None None None None 21059 

OWENSBORO MUNICIPAL UTIL ELMER SMITH STATION 

1374 1 2105900027 001 Coal Steam SCR SCR SCR SCR Scrubber 

21059 

OWENSBORO MUNICIPAL UTIL ELMER SMITH STATION 

1374 2 2105900027 002 Coal Steam None None SCR SCR Scrubber 

21091 WESTERN KY ENERGY CORP COLEMAN STATION 1381 C1 2109100003 001 Coal Steam None None SCR SCR Scrubber 21091 WESTERN KY ENERGY CORP COLEMAN STATION 1381 C2 2109100003 002 Coal Steam None None SCR SCR Scrubber 21091 WESTERN KY ENERGY CORP COLEMAN STATION 1381 C3 2109100003 003 Coal Steam None None SCR SCR Scrubber 21101 HENDERSON MUN POW & LIGHT 1372 6 2110100012 002 Coal Steam None None None None None 21101 HENDERSON MUN POW & LIGHT 1372 5 2110100012 5 Coal Steam None None None None None 21111 LOU GAS & ELEC, CANE RUN 1363 4 0126 04 Coal Steam None None SCR SCR Scrubber 21111 LOU GAS & ELEC, CANE RUN 1363 5 0126 05 Coal Steam None None SCR SCR Scrubber 21111 LOU GAS & ELEC, CANE RUN 1363 6 0126 06 Coal Steam None None SCR SCR Scrubber 21111 LOU GAS & ELEC, MILL CREEK 1364 1 0127 01 Coal Steam None None SCR SCR Scrubber 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

260

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

21111 LOU GAS & ELEC, MILL CREEK 1364 2 0127 02 Coal Steam None None SCR SCR Scrubber 21111 LOU GAS & ELEC, MILL CREEK 1364 3 0127 03 Coal Steam SCR SCR SCR SCR Scrubber 21111 LOU GAS & ELEC, MILL CREEK 1364 4 0127 04 Coal Steam SCR SCR SCR SCR Scrubber 21127 KENTUCKY POWER CO BIG SANDY PLANT 1353 BSU1 2112700003 001 Coal Steam SCR SCR SCR SCR Scrubber 21127 KENTUCKY POWER CO BIG SANDY PLANT 1353 BSU2 2112700003 002 Coal Steam SCR SCR SCR SCR None 21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 1 2114500006 001 Coal Steam None None None None None 

21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 2 2114500006 002 Coal Steam None None None None None 

21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 3 2114500006 003 Coal Steam None None None None None 

21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 4 2114500006 004 Coal Steam None None None None None 

21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 5 2114500006 005 Coal Steam None None None None None 

21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 6 2114500006 006 Coal Steam None None None None None 

21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 7 2114500006 007 Coal Steam None None None None None 

21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 8 2114500006 008 Coal Steam None None None None None 

21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 9 2114500006 009 Coal Steam None None None None None 

21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 10 2114500006 016 Coal Steam None None None None None 

21161 EAST KY POWER COOP SPURLOCK ST. MAYSVILLE 6041 1 2116100009 001 Coal Steam SCR SCR SCR SCR None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

261

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

21161 EAST KY POWER COOP SPURLOCK ST. MAYSVILLE 6041 2 2116100009 002 Coal Steam SCR SCR SCR SCR None 21167 KENTUCKY UTILITIES CO BROWN FACILITY 1355 1 2116700001 001 Coal Steam None None None None Scrubber 21167 KENTUCKY UTILITIES CO BROWN FACILITY 1355 2 2116700001 002 Coal Steam None None SCR SCR Scrubber 21167 KENTUCKY UTILITIES CO BROWN FACILITY 1355 3 2116700001 003 Coal Steam None None SCR SCR Scrubber 21177 KENTUCKY UTILITIES CO GREEN RIVER STATION 1357 4 2117700001 003 Coal Steam None None None None None 21177 KENTUCKY UTILITIES CO GREEN RIVER STATION 1357 5 2117700001 004 Coal Steam None None None None None 21177 TVA PARADISE STEAM PLANT 1378 1 2117700006 001 Coal Steam SCR SCR SCR SCR Scrubber 21177 TVA PARADISE STEAM PLANT 1378 2 2117700006 002 Coal Steam SCR SCR SCR SCR Scrubber 21177 TVA PARADISE STEAM PLANT 1378 3 2117700006 003 Coal Steam SCR SCR SCR SCR Scrubber 21183 WESTERN KY ENERGY CORP WILSON STATION 6823 W1 2118300069 001 Coal Steam SCR SCR SCR SCR Scrubber 21199 EAST KY POWER COOP JOHN SHERMAN COOPER 1384 1 2119900005 001 Coal Steam None None None None None 21199 EAST KY POWER COOP JOHN SHERMAN COOPER 1384 2 2119900005 002 Coal Steam SCR SCR SCR SCR None 21223 LOUISVILLE GAS & ELECTRIC TRIMBLE CO GEN 6071 1 2122300002 001 Coal Steam SCR SCR SCR SCR Scrubber 21233 HENDERSON STATION 2 1382 H1 2123300001- A 002 Coal Steam SCR SCR SCR SCR Scrubber 21233 HENDERSON STATION 2 1382 H2 2123300001- A 003 Coal Steam SCR None SCR SCR Scrubber 21233 WESTERN KY ENERGY CORP REID 1383 R1 2123300001- B 001 Coal Steam None None None None None 21233 WESTERN KY ENERGY CORP GREEN STATION 6639 G1 2123300052 001 Coal Steam None None SCR SCR Scrubber 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

262

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

21233 WESTERN KY ENERGY CORP GREEN STATION 6639 G2 2123300052 002 Coal Steam None None SCR SCR Scrubber 21239 KENTUCKY UTILITIES TYRONE FACILITY 1361 5 2123900001 005 Coal Steam None None None None None 28011 ENTERGY MISSISSIPPI INC, DELTA PLANT 2051 1 2801100031 001 O/G Steam O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement 28011 ENTERGY MISSISSIPPI INC, DELTA PLANT 2051 2801100031 002 O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement 28011 ENTERGY MISSISSIPPI INC, DELTA PLANT 2051 2 2801100031 003 O/G Steam O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement 28011 ENTERGY MISSISSIPPI INC, DELTA PLANT 2051 2801100031 004 O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement 28019 CHOCTAW GENERATION LLP, RED HILLS GENERATING 55076 AA001 2801900011 001A Coal Steam SCR SCR SCR SCR Scrubber 28019 CHOCTAW GENERATION LLP, RED HILLS GENERATING 55076 AA002 2801900011 001B None None None None None 28035 

MISSISSIPPI POWER COMPANY, PLANT EATON 

2046 2803500038 001 O/G Steam No Operation No Operation No Operation No Operation No Operation 

28035 

MISSISSIPPI POWER COMPANY, PLANT EATON 

2046 2803500038 002 O/G Steam No Operation No Operation No Operation No Operation No Operation 

28035 

MISSISSIPPI POWER COMPANY, PLANT EATON 

2046 2803500038 003 O/G Steam No Operation No Operation No Operation No Operation No Operation 

28047 

MISSISSIPPI POWER COMPANY, PLANT JACK WATSON 

2049 1 2804700055 001 O/G Steam No Operation No Operation No Operation No Operation No Operation 

28047 

MISSISSIPPI POWER COMPANY, PLANT JACK WATSON 

2049 2 2804700055 002 O/G Steam No Operation No Operation No Operation No Operation No Operation 

28047 

MISSISSIPPI POWER COMPANY, PLANT JACK WATSON 

2049 3 2804700055 003 O/G Steam No Operation No Operation No Operation No Operation No Operation 

28047 

MISSISSIPPI POWER COMPANY, PLANT JACK WATSON 

2049 4 2804700055 004 Coal Steam None SCR SCR SCR None 

28047 

MISSISSIPPI POWER COMPANY, PLANT JACK WATSON 

2049 5 2804700055 005 Coal Steam None SCR SCR SCR None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

263

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

28049 ENTERGY MISSISSIPPI INC, REX BROWN PLANT 2053 4 2804900112 001 O/G Steam O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement 28049 ENTERGY MISSISSIPPI INC, REX BROWN PLANT 2053 3 2804900112 002 O/G Steam O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement 28059 

MISSISSIPPI POWER COMPANY, PLANT DANIEL 

6073 1 2805900090 001 Coal Steam None SCR SCR SCR None 

28059 

MISSISSIPPI POWER COMPANY, PLANT DANIEL 

6073 2 2805900090 002 Coal Steam None SCR SCR SCR None 

28067 

MOSELLE SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION 

2070 1 2806700035 001 O/G Steam No Operation No Operation No Operation No Operation No Operation 

28067 

MOSELLE SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION 

2070 2 2806700035 002 O/G Steam No Operation No Operation No Operation No Operation No Operation 

28067 

MOSELLE SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION 

2070 3 2806700035 003 O/G Steam No Operation No Operation No Operation No Operation No Operation 

28073 

RD MORROW SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION 

6061 1 2807300021 001 Coal Steam None None SCR SCR Scrubber 

28073 

RD MORROW SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION 

6061 2 2807300021 002 Coal Steam None None SCR SCR Scrubber 

28075 

MISSISSIPPI POWER COMPANY, PLANT SWEATT 

2048 1 2807500032 001 O/G Steam No Operation No Operation No Operation No Operation No Operation 

28075 

MISSISSIPPI POWER COMPANY, PLANT SWEATT 

2048 2 2807500032 002 O/G Steam No Operation No Operation No Operation No Operation No Operation 

28083 GREENWOOD UTILITIES, HENDERSON STATION 2062 H1 2808300048 001 O/G Steam None None None None No Operation 28083 GREENWOOD UTILITIES, HENDERSON STATION 2062 H3 2808300048 003 O/G Steam None None None None No Operation 28149 ENTERGY MISSISSIPPI INC, BAXTER WILSON 2050 1 2814900027 001 O/G Steam O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement 28149 ENTERGY MISSISSIPPI INC, BAXTER WILSON 2050 2 2814900027 002 O/G Steam O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement 28151 ENTERGY MISSISSIPPI INC, GERALD ANDRUS 8054 1 2815100048 001 O/G Steam No Operation No Operation No Operation No Operation No Operation 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

264

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

28163 YAZOO CITY PUBLIC SERVICE COMMISSION 2067 3 2816300005 001 O/G Steam O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement O/G Early Retirement 37017 ELIZABETHTOWN POWER, LLC 10380 UNIT1 3701700043 G- 17A Coal Steam None None None None None 37017 ELIZABETHTOWN POWER, LLC 10380 UNIT2 3701700043 G- 17B None None None None None 37019 COGENTRIX OF NORTH CAROLINA INC - SOUTHPORT 10378 GEN1 3701900067 G-29 Coal Steam None None None None None 37019 COGENTRIX OF NORTH CAROLINA INC - SOUTHPORT 10378 GEN2 3701900067 G-30 Coal Steam None None None None None 37021 CAROLINA POWER & LIGHT ASHEVILLE STEAM 2706 1 628 1 Coal Steam SCR SCR SCR SCR Scrubber 37021 CAROLINA POWER & LIGHT ASHEVILLE STEAM 2706 2 628 2 Coal Steam SCR SCR SCR SCR Scrubber 37025 KANNAPOLIS ENERGY PARTNERS LLC 3702500113 G-2 Coal Steam None None None None None 37025 KANNAPOLIS ENERGY PARTNERS LLC 3702500113 G-3 Coal Steam None None None None None 37035 DUKE ENERGY CORPORATION MARSHALL STEAM 2727 3 3703500073 G-1 Coal Steam SNCR SCR SCR SCR Scrubber 37035 DUKE ENERGY CORPORATION MARSHALL STEAM 2727 4 3703500073 G-2 Coal Steam SNCR SCR SCR SCR Scrubber 37035 DUKE ENERGY CORPORATION MARSHALL STEAM 2727 1 3703500073 G-4 Coal Steam SNCR SCR SCR SCR Scrubber 37035 DUKE ENERGY CORPORATION MARSHALL STEAM 2727 2 3703500073 G-5 Coal Steam SNCR SCR SCR SCR Scrubber 37037 

PROGRESS ENERGY CAROLINAS CAPE FEAR 

2708 5 3703700063 G-1 Coal Steam SNCR SNCR SNCR SNCR None 

37037 

PROGRESS ENERGY CAROLINAS CAPE FEAR 

2708 6 3703700063 G-2 Coal Steam SNCR SNCR SNCR SNCR None 

37071 DUKE ENERGY CORPORATION ALLEN STEAM 2718 1 3707100039 G-14 Coal Steam SNCR SNCR SNCR SNCR Scrubber 37071 DUKE ENERGY CORPORATION ALLEN STEAM 2718 2 3707100039 G-15 Coal Steam SNCR SNCR SNCR SNCR Scrubber 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

265

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

37071 DUKE ENERGY CORPORATION ALLEN STEAM 2718 3 3707100039 G-16 Coal Steam SNCR SCR SCR SCR Scrubber 37071 DUKE ENERGY CORPORATION ALLEN STEAM 2718 4 3707100039 G-17 Coal Steam SNCR SCR SCR SCR Scrubber 37071 DUKE ENERGY CORPORATION ALLEN STEAM 2718 5 3707100039 G-18 Coal Steam SNCR SCR SCR SCR Scrubber 37071 DUKE ENERGY CORPORATION RIVERBEND STEAM 2732 7 3707100040 G-17 Coal Steam SNCR SNCR SNCR SNCR None 37071 DUKE ENERGY CORPORATION RIVERBEND STEAM 2732 8 3707100040 G-18 Coal Steam SNCR SNCR SNCR SNCR None 37071 DUKE ENERGY CORPORATION RIVERBEND STEAM 2732 9 3707100040 G-19 Coal Steam SNCR SNCR SNCR SNCR None 37071 DUKE ENERGY CORPORATION RIVERBEND STEAM 2732 10 3707100040 G-20 Coal Steam SNCR SNCR SNCR SNCR None 37083 ROANOKE VALLEY ENERGY FACILITY 3708300174 G-27 Coal Steam None None None None None 37083 ROANOKE VALLEY ENERGY FACILITY 3708300174 G-7 Coal Steam None None None None None 37129 L V SUTTON STEAM ELECTRIC PLANT 2713 1 3712900036 G-187 Coal Steam None SNCR SNCR SNCR None 37129 L V SUTTON STEAM ELECTRIC PLANT 2713 2 3712900036 G-188 Coal Steam None SCR SCR SCR None 37129 L V SUTTON STEAM ELECTRIC PLANT 2713 3 3712900036 G-189 Coal Steam None SCR SCR SCR None 37145 CP&L - ROXBORO STEAM ELECTRIC PLANT 2712 1 3714500029 G-29 Coal Steam SCR SCR SCR SCR Scrubber 37145 CP&L - ROXBORO STEAM ELECTRIC PLANT 2712 2 3714500029 G-30 Coal Steam SCR SCR SCR SCR Scrubber 37145 CP&L - ROXBORO STEAM ELECTRIC PLANT 2712 3A 3714500029 G- 35A Coal Steam SCR SCR SCR SCR Scrubber 37145 CP&L - ROXBORO STEAM ELECTRIC PLANT 2712 3B 3714500029 G- 35B Coal Steam SCR SCR SCR SCR Scrubber 37145 CP&L - ROXBORO STEAM ELECTRIC PLANT 2712 4A 3714500029 G- 36A Coal Steam SCR SCR SCR SCR Scrubber 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

266

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

37145 CP&L - ROXBORO STEAM ELECTRIC PLANT 2712 4B 3714500029 G- 36B Coal Steam SCR SCR SCR SCR Scrubber 37145 CP&L - MAYO FACILITY 6250 1A 3714500045 G- 46A Coal Steam SCR SCR SCR SCR Scrubber 37145 CP&L - MAYO FACILITY 6250 1B 3714500045 G- 46B Coal Steam SCR SCR SCR SCR Scrubber 37155 

PROGRESS ENERGY CAROLINAS, INC., W.H. WEATHERSPOON 

2716 1 3715500147 G-24 Coal Steam None SNCR SNCR SNCR None 

37155 

PROGRESS ENERGY CAROLINAS, INC., W.H. WEATHERSPOON 

2716 2 3715500147 G-25 Coal Steam None SNCR SNCR SNCR None 

37155 

PROGRESS ENERGY CAROLINAS, INC., W.H. WEATHERSPOON 

2716 3 3715500147 G-26 Coal Steam None SNCR SNCR SNCR None 

37155 LUMBERTON POWER, LLC 10382 UNIT1 3715500166 G- 17A Coal Steam None None None None None 37155 LUMBERTON POWER, LLC 10382 UNIT2 3715500166 G- 17B None None None None None 37157 DUKE ENERGY CORP DAN RIVER STEAM 2723 3 3715700015 G-21 Coal Steam None SNCR SNCR SNCR None 37157 DUKE ENERGY CORP DAN RIVER STEAM 2723 1 3715700015 G-22 Coal Steam None SNCR SNCR SNCR None 37157 DUKE ENERGY CORP DAN RIVER STEAM 2723 2 3715700015 G-23 Coal Steam None SNCR SNCR SNCR None 37159 DUKE ENERGY CORPORATION BUCK STEAM 2720 5 3715900004 G-1 Coal Steam None SNCR SNCR SNCR None 37159 DUKE ENERGY CORPORATION BUCK STEAM 2720 6 3715900004 G-2 Coal Steam None SNCR SNCR SNCR None 37159 DUKE ENERGY CORPORATION BUCK STEAM 2720 7 3715900004 G-3 Coal Steam SNCR SNCR SNCR SNCR None 37159 DUKE ENERGY CORPORATION BUCK STEAM 2720 8 3715900004 G-4 Coal Steam SNCR SNCR SNCR SNCR None 37159 DUKE ENERGY CORPORATION BUCK STEAM 2720 9 3715900004 G-5 Coal Steam SNCR SNCR SNCR SNCR None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

267

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

37161 DUKE ENERGY CORPORATION CLIFFSIDE STEAM 2721 1 3716100028 G-82 Coal Steam None SNCR SNCR SNCR None 37161 DUKE ENERGY CORPORATION CLIFFSIDE STEAM 2721 2 3716100028 G-83 Coal Steam None SNCR SNCR SNCR None 37161 DUKE ENERGY CORPORATION CLIFFSIDE STEAM 2721 3 3716100028 G-84 Coal Steam None SNCR SNCR SNCR None 37161 DUKE ENERGY CORPORATION CLIFFSIDE STEAM 2721 4 3716100028 G-85 Coal Steam None SNCR SNCR SNCR None 37161 DUKE ENERGY CORPORATION CLIFFSIDE STEAM 2721 5 3716100028 G-86 Coal Steam SCR SCR SCR SCR None 37161 DUKE ENERGY CORPORATION CLIFFSIDE STEAM 2721 6 3716100028 G-87 No Operation Not in IPM SCR Not in IPM No Operation 37161 DUKE ENERGY CORPORATION CLIFFSIDE STEAM 2721 7 3716100028 G-88 No Operation Not in IPM SCR Not in IPM No Operation 37169 DUKE ENERGY CORP BELEWS CREEK STEAM 8042 1 3716900004 G-17 Coal Steam SCR SCR SCR SCR Scrubber 37169 DUKE ENERGY CORP BELEWS CREEK STEAM 8042 2 3716900004 G-18 Coal Steam SCR SCR SCR SCR Scrubber 37191 PROGRESS ENERGY F LEE PLANT 2709 1 3719100017 G-2 Coal Steam None SNCR SNCR SNCR None 37191 PROGRESS ENERGY F LEE PLANT 2709 2 3719100017 G-3 Coal Steam None SNCR SNCR SNCR None 37191 PROGRESS ENERGY F LEE PLANT 2709 3 3719100017 G-4 Coal Steam None SCR SCR SCR None 45003 SCE&G:URQUHART 3295 URQ3 0080-0011 003 Coal Steam None None None None None 45003 SCE&G:SRS AREA D 0080-0044 001 Coal Steam None None None None None 45003 SCE&G:SRS AREA D 0080-0044 002 None None None None None 45003 SCE&G:SRS AREA D 0080-0044 003 None None None None None 45003 SCE&G:SRS AREA D 0080-0044 004 None None None None None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

268

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

45007 DUKE ENERGY:LEE 3264 1 0200-0004 001 Coal Steam None None None None None 45007 DUKE ENERGY:LEE 3264 2 0200-0004 002 Coal Steam None None None None None 45007 DUKE ENERGY:LEE 3264 3 0200-0004 003 Coal Steam None None None None None 45015 SANTEE COOPER JEFFERIES 3319 1 0420-0003 001 O/G Steam No Operation No Operation No Operation No Operation No Operation 45015 SANTEE COOPER JEFFERIES 3319 2 0420-0003 002 O/G Steam No Operation No Operation No Operation No Operation No Operation 45015 SANTEE COOPER JEFFERIES 3319 3 0420-0003 003 Coal Steam None SCR None SCR None 45015 SANTEE COOPER JEFFERIES 3319 4 0420-0003 004 Coal Steam None None None None None 45015 SCE&G:WILLIAMS 3298 WIL1 0420-0006 001 Coal Steam SCR SCR SCR SCR None 45015 SANTEE COOPER CROSS 130 1 0420-0030 001 Coal Steam SCR SCR SCR SCR Scrubber Upgrade 45015 SANTEE COOPER CROSS 130 2 0420-0030 002 Coal Steam SCR SCR SCR SCR Scrubber Upgrade 45015 SANTEE COOPER CROSS 130 3 0420-0030 3 Coal Steam SCR SCR SCR SCR Scrubber 45015 SANTEE COOPER CROSS 130 4 0420-0030 4 No Operation No Operation No Operation No Operation No Operation 45029 SCE&G:CANADYS 3280 CAN1 0740-0002 001 Coal Steam None None None None None 45029 SCE&G:CANADYS 3280 CAN2 0740-0002 002 Coal Steam None None None None None 45029 SCE&G:CANADYS 3280 CAN3 0740-0002 003 Coal Steam None None None None Scrubber 45031 PROGRESS ENERGY ROBINSON STATION 3251 1 0820-0002 001 Coal Steam None None None None None 45043 SANTEE COOPER WINYAH 6249 1 1140-0005 001 Coal Steam SCR SCR SCR SCR Scrubber 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

269

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

45043 SANTEE COOPER WINYAH 6249 2 1140-0005 002 Coal Steam SCR SCR SCR SCR Scrubber 45043 SANTEE COOPER WINYAH 6249 3 1140-0005 003 Coal Steam SCR SCR SCR SCR Scrubber Upgrade 45043 SANTEE COOPER WINYAH 6249 4 1140-0005 004 Coal Steam SCR SCR SCR SCR Scrubber Upgrade 45051 SANTEE COOPER GRAINGER 3317 1 1340-0003 001 Coal Steam None None None None None 45051 SANTEE COOPER GRAINGER 3317 2 1340-0003 002 Coal Steam None None None None None 45063 SCE&G:MCMEEKIN 3287 MCM1 1560-0003 001 Coal Steam None None None None None 45063 SCE&G:MCMEEKIN 3287 MCM2 1560-0003 002 Coal Steam None None None None None 45075 SCE&G:COPE 7210 COP1 1860-0044 001 Coal Steam None None None None Scrubber 45079 SCE&G:WATEREE 3297 WAT1 1900-0013 001 Coal Steam SCR SCR SCR SCR Scrubber 45079 SCE&G:WATEREE 3297 WAT2 1900-0013 002 Coal Steam SCR SCR SCR SCR Scrubber 47001 TVA BULL RUN FOSSIL PLANT 3396 1 0009 001 Coal Steam SCR SCR SCR SCR Scrubber 47073 TVA JOHN SEVIER FOSSIL PLANT 3405 1 0007 001 Coal Steam None None SCR SCR None 47073 TVA JOHN SEVIER FOSSIL PLANT 3405 2 0007 002 Coal Steam None None SCR SCR None 47073 TVA JOHN SEVIER FOSSIL PLANT 3405 3 0007 003 Coal Steam None None SCR SCR None 47073 TVA JOHN SEVIER FOSSIL PLANT 3405 4 0007 004 Coal Steam None None SCR SCR None 47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 1 0011 001 Coal Steam None SCR SCR SCR None 47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 2 0011 002 Coal Steam None SCR SCR SCR None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

270

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 3 0011 003 Coal Steam None SCR SCR SCR None 47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 4 0011 004 Coal Steam None SCR SCR SCR None 47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 5 0011 005 Coal Steam None SCR SCR SCR None 47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 6 0011 006 Coal Steam None SCR SCR SCR None 47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 7 0011 007 Coal Steam None SCR SCR SCR None 47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 8 0011 008 Coal Steam None SCR SCR SCR None 47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 9 0011 009 Coal Steam None SCR SCR SCR None 47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 10 0011 010 Coal Steam None SCR SCR SCR None 47145 TVA KINGSTON FOSSIL PLANT 3407 1 0013 001 Coal Steam SCR SCR SCR SCR None 47145 TVA KINGSTON FOSSIL PLANT 3407 2 0013 002 Coal Steam SCR SCR SCR SCR None 47145 TVA KINGSTON FOSSIL PLANT 3407 3 0013 003 Coal Steam SCR SCR SCR SCR None 47145 TVA KINGSTON FOSSIL PLANT 3407 4 0013 004 Coal Steam SCR SCR SCR SCR None 47145 TVA KINGSTON FOSSIL PLANT 3407 5 0013 005 Coal Steam SCR SCR SCR SCR None 47145 TVA KINGSTON FOSSIL PLANT 3407 6 0013 006 Coal Steam SCR SCR SCR SCR None 47145 TVA KINGSTON FOSSIL PLANT 3407 7 0013 007 Coal Steam SCR SCR SCR SCR None 47145 TVA KINGSTON FOSSIL PLANT 3407 8 0013 008 Coal Steam SCR SCR SCR SCR None 47145 TVA KINGSTON FOSSIL PLANT 3407 9 0013 009 Coal Steam SCR None SCR SCR None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

271

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

47157 ALLEN FOSSIL PLANT 3393 1 00528 Boilr1 Coal Steam SCR SCR SCR SCR None 47157 ALLEN FOSSIL PLANT 3393 2 00528 Boilr2 Coal Steam SCR SCR SCR SCR None 47157 ALLEN FOSSIL PLANT 3393 3 00528 Boilr3 Coal Steam SCR SCR SCR SCR None 47161 TVA CUMBERLAND FOSSIL PLANT 3399 1 0011 001 Coal Steam SCR SCR SCR SCR Scrubber 47161 TVA CUMBERLAND FOSSIL PLANT 3399 2 0011 002 Coal Steam SCR SCR SCR SCR Scrubber 47165 TVA GALLATIN FOSSIL PLANT 3403 1 0025 001 Coal Steam None None None None None 47165 TVA GALLATIN FOSSIL PLANT 3403 2 0025 002 Coal Steam None None None None None 47165 TVA GALLATIN FOSSIL PLANT 3403 3 0025 003 Coal Steam None None None None None 47165 TVA GALLATIN FOSSIL PLANT 3403 4 0025 004 Coal Steam None None None None None 51031 DOMINION - ALTAVISTA POWER STATION 10773 1 00156 1 Coal Steam SNCR SNCR SNCR SNCR Scrubber 51031 DOMINION - ALTAVISTA POWER STATION 10773 2 00156 2 None None None None None 51041 DOMINION - CHESTERFIELD POWER STATION 3797 3 00002 3 Coal Steam None None None None None 51041 DOMINION - CHESTERFIELD POWER STATION 3797 4 00002 4 Coal Steam SCR None SCR SCR None 51041 DOMINION - CHESTERFIELD POWER STATION 3797 5 00002 6 Coal Steam SCR None SCR SCR None 51041 DOMINION - CHESTERFIELD POWER STATION 3797 6 00002 8 Coal Steam SCR SCR SCR SCR Scrubber 51065 DOMINION - BREMO POWER STATION 3796 3 00001 1 Coal Steam None None None None None 51065 DOMINION - BREMO POWER STATION 3796 4 00001 2 Coal Steam SNCR SNCR SNCR SNCR None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

272

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

51071 AMERICAN ELECTRIC POWER GLEN LYN 3776 51 00002 1 Coal Steam None None None None None 51071 AMERICAN ELECTRIC POWER GLEN LYN 3776 52 00002 2 Coal Steam None None None None None 51071 AMERICAN ELECTRIC POWER GLEN LYN 3776 6 00002 3 Coal Steam None None None None None 51083 DOMINION - CLOVER POWER STATION 7213 1 00046 1 Coal Steam SNCR SNCR SNCR SNCR Scrubber 51083 DOMINION - CLOVER POWER STATION 7213 2 00046 2 Coal Steam SNCR SNCR SNCR SNCR Scrubber 51099 BIRCHWOOD POWER PARTNERS, L.P. 54304 1 00012 1 Coal Steam SCR SCR SCR SCR Scrubber 51117 Mecklenburg Cogeneration Facility 52007 GEN1 00051 1 Coal Steam None None None None Scrubber 51117 Mecklenburg Cogeneration Facility 52007 GEN2 00051 2 Coal Steam None None None None Scrubber 51153 DOMINION - POSSUM POINT 3804 3 00002 3 Coal Steam None Combined Cycle None Combined Cycle None 51153 DOMINION - POSSUM POINT 3804 4 00002 4 Coal Steam None Combined Cycle None Combined Cycle None 51153 DOMINION - POSSUM POINT 3804 5 00002 5 O/G Steam None No Operation None No Operation None 51153 DOMINION - POSSUM POINT 3804 6 00002 Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle Combined Cycle 51167 AMERICAN ELECTRIC POWER CLINCH RIVER PLANT 3775 1 00003 1 Coal Steam None None None SCR None 51167 AMERICAN ELECTRIC POWER CLINCH RIVER PLANT 3775 2 00003 2 Coal Steam None None None SCR None 51167 AMERICAN ELECTRIC POWER CLINCH RIVER PLANT 3775 3 00003 3 Coal Steam None None None SCR None 51175 LG&E Westmoreland Southampton 10774 GEN1 00051 1 Coal Steam None None None None Scrubber 51175 LG&E Westmoreland Southampton 00051 2 None None None None None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

273

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

51175 LG&E Westmoreland Southampton 00051 4 None None None None None 51199 DOMINION - YORKTOWN POWER STATION 3809 3 00001 3 O/G Steam SNCR No Operation SNCR No Operation None 51199 DOMINION - YORKTOWN POWER STATION 3809 2 00001 5 Coal Steam SNCR SNCR SNCR SNCR None 51199 DOMINION - YORKTOWN POWER STATION 3809 1 00001 6 Coal Steam SNCR SNCR SNCR SNCR None 51510 POTOMAC RIVER GENERATING STATION 3788 1 00003 1 Coal Steam SNCR Coal Early Retirement SNCR Coal Early Retirement None 51510 POTOMAC RIVER GENERATING STATION 3788 2 00003 2 Coal Steam SNCR Coal Early Retirement SNCR Coal Early Retirement None 51510 POTOMAC RIVER GENERATING STATION 3788 3 00003 3 Coal Steam SNCR None SNCR None None 51510 POTOMAC RIVER GENERATING STATION 3788 4 00003 4 Coal Steam SNCR None SNCR None None 51510 POTOMAC RIVER GENERATING STATION 3788 5 00003 5 Coal Steam SNCR None SNCR None None 51550 DOMINION - CHESAPEAKE 3803 1 00026 1 Coal Steam SNCR SNCR SNCR SNCR None 51550 DOMINION - CHESAPEAKE 3803 2 00026 2 Coal Steam SNCR SNCR SNCR SNCR None 51550 DOMINION - CHESAPEAKE 3803 3 00026 3 Coal Steam SCR None SCR SCR None 51550 DOMINION - CHESAPEAKE 3803 4 00026 4 Coal Steam SCR None SCR SCR None 54023 MOUNT STORM POWER PLANT 3954 1 0003 001 Coal Steam SCR SCR SCR SCR Scrubber 54023 MOUNT STORM POWER PLANT 3954 2 0003 002 Coal Steam SCR SCR SCR SCR Scrubber 54023 MOUNT STORM POWER PLANT 3954 3 0003 003 Coal Steam SCR SCR SCR SCR Scrubber 54023 NORTH BRANCH POWER STATION 7537 1A 0014 001 Coal Steam None None None None None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

274

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

54023 NORTH BRANCH POWER STATION 7537 1B 0014 002 Coal Steam None None None None None 54033 MONONGAHELA POWER CO HARRISON 3944 1 0015 001 Coal Steam SCR SCR SCR SCR Scrubber 54033 MONONGAHELA POWER CO HARRISON 3944 2 0015 002 Coal Steam SCR SCR SCR SCR Scrubber 54033 MONONGAHELA POWER CO HARRISON 3944 3 0015 003 Coal Steam SCR SCR SCR SCR Scrubber 54039 APPALACHIAN POWER KANAWHA RIVER PLANT 3936 1 0006 001 Coal Steam None None SCR SCR None 54039 APPALACHIAN POWER KANAWHA RIVER PLANT 3936 2 0006 002 Coal Steam None None SCR SCR None 54049 MONONGAHELA POWER CO. RIVESVILLE POWER 3945 7 0009 001 Coal Steam None Coal Early Retirement None Coal Early Retirement None 54049 MONONGAHELA POWER CO. RIVESVILLE POWER 3945 8 0009 002 Coal Steam None Coal Early Retirement None Coal Early Retirement None 54049 AMERICAN BITUMINOUS POWER GRANT TOWN PLT 10151 0026 001 None None None None Scrubber 54049 GRANT TOWN POWER PLANT 10151 GEN1 ORIS10151 GEN1 Coal Steam None None None None Scrubber 54051 OHIO POWER MITCHELL PLANT 3948 1 0005 001 Coal Steam SCR SCR SCR SCR Scrubber 54051 OHIO POWER MITCHELL PLANT 3948 2 0005 002 Coal Steam SCR SCR SCR SCR Scrubber 54051 OHIO POWER KAMMER PLANT 3947 1 0006 001 Coal Steam None SCR SCR SCR None 54051 OHIO POWER KAMMER PLANT 3947 2 0006 002 Coal Steam None SCR SCR SCR None 54051 OHIO POWER KAMMER PLANT 3947 3 0006 003 Coal Steam None SCR SCR SCR None 54053 APPALACHIAN POWER CO. PHILIP SPORN PLANT 3938 11 0001 001 Coal Steam None None SCR SCR None 54053 APPALACHIAN POWER CO. PHILIP SPORN PLANT 3938 21 0001 002 Coal Steam None None SCR SCR None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

275

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

54053 APPALACHIAN POWER CO. PHILIP SPORN PLANT 3938 31 0001 003 Coal Steam None None SCR SCR None 54053 APPALACHIAN POWER CO. PHILIP SPORN PLANT 3938 41 0001 004 Coal Steam None None SCR SCR None 54053 APPALACHIAN POWER CO. PHILIP SPORN PLANT 3938 51 0001 005 Coal Steam None None SCR SCR None 54053 APPALACHIAN POWER MOUNTAINEER PLANT 6264 1 0009 Coal Steam SCR SCR SCR SCR Scrubber 54061 MONONGAHELA POWER CO. FORT MARTIN POWER 3943 1 0001 001 Coal Steam SNCR SNCR SNCR SNCR None 54061 MONONGAHELA POWER CO. FORT MARTIN POWER 3943 2 0001 002 Coal Steam SNCR SNCR SNCR SNCR None 54061 MORGANTOWN ENERGY ASSOCIATES 0027 043 None None None None None 54061 MORGANTOWN ENERGY FACILITY 10743 GEN1 ORIS10743 GEN1 Coal Steam None None None None None 54073 MONONGAHELA POWER CO. WILLOW ISLAND 3946 1 0004 001 Coal Steam None Coal Early Retirement None Coal Early Retirement None 54073 MONONGAHELA POWER CO. WILLOW ISLAND 3946 2 0004 002 Coal Steam None SCR SCR SCR None 54073 MONONGAHELA POWER CO PLEASANTS POWER STATION 6004 1 0005 001 Coal Steam SCR SCR SCR SCR Scrubber 54073 MONONGAHELA POWER CO PLEASANTS POWER STATION 6004 2 0005 002 Coal Steam SCR SCR SCR SCR Scrubber 54077 MONONGAHELA POWER CO ALBRIGHT 3942 1 0001 001 Coal Steam None Coal Early Retirement Coal Early Retirement Coal Early Retirement None 54077 MONONGAHELA POWER CO ALBRIGHT 3942 2 0001 002 Coal Steam None Coal Early Retirement Coal Early Retirement Coal Early Retirement None 54077 MONONGAHELA POWER CO ALBRIGHT 3942 3 0001 003 Coal Steam None None SCR SCR None 54079 APPALACHIAN POWER JOHN E AMOS PLANT 3935 1 0006 001 Coal Steam SCR SCR SCR SCR Scrubber 54079 APPALACHIAN POWER JOHN E AMOS PLANT 3935 2 0006 002 Coal Steam SCR SCR SCR SCR Scrubber 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix H 

276

APPENDIX H: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE BASE G/G2 INVENTO

Post-Combustion Contro

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 2009 

Controls 

IPM 

NOx 2009 

Controls 

VISTAS 

NOx 2018 

Controls 

IPM 

NOx 2018 

Controls 

VISTAS 

SO2 2009 

Controls 

54079 APPALACHIAN POWER JOHN E AMOS PLANT 3935 3 0006 003 Coal Steam SCR SCR SCR SCR Scrubber 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix I 277

APPENDIX I: 

COMPARISON OF EGU CONTROLS FOR COAL AND OIL/GAS UNITS 

BASED ON IPM MODELING AND STATE-PROVIDED INFORMATION 

FOR THE B&F INVENTORY
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix I 

278

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

01033 TVA COLBERT 47 1 0010 010 Coal Steam None None SCR SCR None 01033 TVA COLBERT 47 2 0010 011 Coal Steam None None SCR SCR None 01033 TVA COLBERT 47 3 0010 012 Coal Steam None None SCR SCR None 01033 TVA COLBERT 47 4 0010 013 Coal Steam None None SCR SCR None 01033 TVA COLBERT 47 5 0010 014 Coal Steam SCR SCR SCR SCR Scrubb01055 

ALABAMA POWER COMPANY GADSDEN 

7 1 0002 002 Coal Steam None None None None None 

01055 

ALABAMA POWER COMPANY GADSDEN 

7 2 0002 003 Coal Steam None None None None None 

01063 

ALABAMA POWER COMPANY GREENE COUNTY 

10 1 0001 002 Coal Steam SCR SCR SCR SCR None 

01063 

ALABAMA POWER COMPANY GREENE COUNTY 

10 2 0001 003 Coal Steam SCR SCR SCR SCR None 

01071 TVA - WIDOWS CREEK 50 1 0008 002 Coal Steam SCR SCR SCR SCR None 01071 TVA - WIDOWS CREEK 50 2 0008 003 Coal Steam SCR SCR SCR SCR None 01071 TVA - WIDOWS CREEK 50 3 0008 004 Coal Steam SCR SCR SCR SCR None 01071 TVA - WIDOWS CREEK 50 4 0008 005 Coal Steam SCR SCR SCR SCR None 01071 TVA - WIDOWS CREEK 50 5 0008 006 Coal Steam SCR SCR SCR SCR None 01071 TVA - WIDOWS CREEK 50 6 0008 007 Coal Steam SCR SCR SCR SCR None 01071 TVA - WIDOWS CREEK 50 7 0008 008 Coal Steam SCR SCR SCR SCR Scrubb
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix I 

279

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

01071 TVA - WIDOWS CREEK 50 8 0008 009 Coal Steam SCR SCR SCR SCR Scrubb01073 

ALABAMA POWER COMPANY (MILLER POWER PLANT) 

6002 4 010730011 001 Coal Steam SCR All Year SCR Summer SCR All Year SCR Summer None 

01073 

ALABAMA POWER COMPANY (MILLER POWER PLANT) 

6002 3 010730011 002 Coal Steam SCR All Year SCR Summer SCR All Year SCR Summer None 

01073 

ALABAMA POWER COMPANY (MILLER POWER PLANT) 

6002 2 010730011 004 Coal Steam SCR All Year SCR Summer SCR All Year SCR Summer None 

01073 

ALABAMA POWER COMPANY (MILLER POWER PLANT) 

6002 1 010730011 005 Coal Steam SCR All Year SCR Summer SCR All Year SCR Summer None 

01097 

ALABAMA POWER COMPANY BARRY 

3 1 1001 002 Coal Steam SNCR None SNCR SCR None 

01097 

ALABAMA POWER COMPANY BARRY 

3 2 1001 003 Coal Steam SNCR None SNCR SCR None 

01097 

ALABAMA POWER COMPANY BARRY 

3 3 1001 004 Coal Steam SNCR None SNCR SCR None 

01097 

ALABAMA POWER COMPANY BARRY 

3 4 1001 005 Coal Steam SNCR None SNCR SCR None 

01097 

ALABAMA POWER COMPANY BARRY 

3 5 1001 006 Coal Steam None None SCR SCR None 

01117 

ALABAMA POWER COMPANY E C GASTON 

26 1 0005 002 Coal Steam None SCR None SCR None 

01117 

ALABAMA POWER COMPANY E C GASTON 

26 2 0005 003 Coal Steam None SCR None SCR None 

01117 

ALABAMA POWER COMPANY E C GASTON 

26 3 0005 004 Coal Steam None SCR None SCR None 

01117 

ALABAMA POWER COMPANY E C GASTON 

26 4 0005 005 Coal Steam None SCR None SCR None 

01117 

ALABAMA POWER COMPANY E C GASTON 

26 5 0005 006 Coal Steam SCR SCR SCR SCR None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix I 

280

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

01127 

ALABAMA POWER COMPANY GORGAS 

8 6 0001 004 Coal Steam None None None None None 

01127 

ALABAMA POWER COMPANY GORGAS 

8 7 0001 005 Coal Steam None None None None None 

01127 

ALABAMA POWER COMPANY GORGAS 

8 8 0001 006 Coal Steam None None None None Scrubb

01127 

ALABAMA POWER COMPANY GORGAS 

8 9 0001 007 Coal Steam None None None None Scrubb

01127 

ALABAMA POWER COMPANY GORGAS 

8 10 0001 008 Coal Steam SCR SCR SCR SCR Scrubb

01129 ALABAMA ELECTRIC COOP CHARLES R LOWMAN 56 1 0001 002 Coal Steam None None None None Scrubb01129 ALABAMA ELECTRIC COOP CHARLES R LOWMAN 56 2 0001 003 Coal Steam SCR SCR SCR SCR Scrubb01129 ALABAMA ELECTRIC COOP CHARLES R LOWMAN 56 3 0001 004 Coal Steam SCR SCR SCR SCR Scrubb12001 GAINESVILLE REGIONAL UTILITIES JOHN R KELLY 664 JRK6 O/G Steam O/G Early Retireme nt O/G Early Retireme nt O/G Early Retireme nt O/G Early Retireme nt O/G Ea

Retirem

nt 

12001 GAINESVILLE REGIONAL UTILITIES JOHN R KELLY 664 JRK7 O/G Steam O/G Early Retireme nt O/G Early Retireme nt O/G Early Retireme nt O/G Early Retireme nt O/G Ea

Retirem

nt 

12001 GAINESVILLE REGIONAL UTILITIES JOHN R KELLY 664 JRK8 0010005 7 O/G Early Retireme nt O/G Early Retireme nt O/G Early Retireme nt O/G Early Retireme nt O/G Ea

Retirem

nt 

12001 CITY OF GAINESVILLE, GRU DEERHAVEN 663 B1 0010006 3 O/G Steam No Operation No Operation No Operation No Operation No Operat12001 CITY OF GAINESVILLE, GRU DEERHAVEN 663 B2 0010006 5 Coal Steam None None SCR SCR None 12005 GULF POWER COMPANY LANSING SMITH PLANT 643 1 0050014 1 Coal Steam None None SCR SCR None 12005 GULF POWER COMPANY LANSING SMITH PLANT 643 2 0050014 2 Coal Steam None None SCR SCR None 12009 FLORIDA POWER & LIGHT (PCC) CAPE CANAVERAL 609 PCC1 0090006 1 O/G Steam None No Operation None No Operation None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix I 

281

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

12009 FLORIDA POWER & LIGHT (PCC) CAPE CANAVERAL 609 PCC2 0090006 2 O/G Steam None No Operation None No Operation None 12011 FLORIDA POWER & LIGHT (PPE) PORT EVERGLADES 617 PPE1 0110036 1 O/G Steam None No Operation None No Operation None 12011 FLORIDA POWER & LIGHT (PPE) PORT EVERGLADES 617 PPE2 0110036 2 O/G Steam None None None None None 12011 FLORIDA POWER & LIGHT (PPE) PORT EVERGLADES 617 PPE3 0110036 3 O/G Steam None None None None None 12011 FLORIDA POWER & LIGHT (PPE) PORT EVERGLADES 617 PPE4 0110036 4 O/G Steam None None None None None 12017 

PROGRESS ENERGY FLORIDA CRYSTAL RIVER 

628 1 0170004 1 Coal Steam None None None None None 

12017 

PROGRESS ENERGY FLORIDA CRYSTAL RIVER 

628 2 0170004 2 Coal Steam None None None None None 

12017 

PROGRESS ENERGY FLORIDA CRYSTAL RIVER 

628 5 0170004 3 Coal Steam None None SCR SCR None 

12017 

PROGRESS ENERGY FLORIDA CRYSTAL RIVER 

628 4 0170004 4 Coal Steam SCR SCR SCR SCR Scrubb

12031 SAINT JOHNS RIVER 207 1 0310045-A 16 SCR SCR SCR SCR Scrubb12031 SAINT JOHNS RIVER 207 2 0310045-A 17 SCR SCR SCR SCR Scrubb12031 NORTHSIDE 667 2A 0310045-B 26 O/G Steam None No Operation None No Operation None 12031 NORTHSIDE 667 1A 0310045-B 27 O/G Steam None No Operation None No Operation None 12031 NORTHSIDE 667 3 0310045-B 3 O/G Steam None None None No Operation None 12031 CEDAR BAY COGENERATION INC. 10672 GEN1 0310337 1 Coal Steam None SNCR None SNCR Scrubb12031 CEDAR BAY COGENERATION INC. 0310337 2 None None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix I 

282

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

12031 CEDAR BAY COGENERATION INC. 0310337 3 None None 12033 

GULF POWER COMPANY CRIST ELECTRIC GENERATION 

641 1 0330045 1 

12033 

GULF POWER COMPANY CRIST ELECTRIC GENERATION 

641 2 0330045 2 O/G Steam 

O/G Early 

Retireme

nt 

O/G Early 

Retireme

nt 

O/G Early 

Retireme

nt 

O/G Early 

Retireme

nt 

O/G Ea

Retirem

nt 

12033 

GULF POWER COMPANY CRIST ELECTRIC GENERATION 

641 3 0330045 3 O/G Steam 

O/G Early 

Retireme

nt 

O/G Early 

Retireme

nt 

O/G Early 

Retireme

nt 

O/G Early 

Retireme

nt 

O/G Ea

Retirem

nt 

12033 

GULF POWER COMPANY CRIST ELECTRIC GENERATION 

641 4 0330045 4 Coal Steam None None None None Scrubb

12033 

GULF POWER COMPANY CRIST ELECTRIC GENERATION 

641 5 0330045 5 Coal Steam None None None None Scrubb

12033 

GULF POWER COMPANY CRIST ELECTRIC GENERATION 

641 6 0330045 6 Coal Steam SNCR SNCR SNCR SNCR Scrubb

12033 

GULF POWER COMPANY CRIST ELECTRIC GENERATION 

641 7 0330045 7 Coal Steam SCR SCR SCR SCR Scrubb

12053 Central Power and Lime Incorporated 10333 GEN1 0530021 18 Coal Steam None None None None Scrubb12057 TAMPA ELECTRIC COMPANY BIG BEND STATION 645 BB01 0570039 1 Coal Steam SCR SCR SCR SCR Scrubb12057 TAMPA ELECTRIC COMPANY BIG BEND STATION 645 BB02 0570039 2 Coal Steam SCR SCR SCR SCR Scrubb12057 TAMPA ELECTRIC COMPANY BIG BEND STATION 645 BB03 0570039 3 Coal Steam SCR SCR SCR SCR Scrubb12057 TAMPA ELECTRIC COMPANY BIG BEND STATION 645 BB04 0570039 4 Coal Steam SCR SCR SCR SCR Scrubb12057 TAMPA ELECTRIC COMPANY F.J. GANNON STATION 646 GB01 0570040 1 No Operation No Operation No Operation No Operation No Operat12057 TAMPA ELECTRIC COMPANY F.J. GANNON STATION 646 GB02 0570040 2 No Operation No Operation No Operation No Operation No Operat12057 TAMPA ELECTRIC COMPANY F.J. GANNON STATION 646 GB03 0570040 3 No Operation No Operation No Operation No Operation No Operat
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix I 

283

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

12057 TAMPA ELECTRIC COMPANY F.J. GANNON STATION 646 GB04 0570040 4 No Operation No Operation No Operation No Operation No Operat12057 TAMPA ELECTRIC COMPANY F.J. GANNON STATION 646 GB05 0570040 5 No Operation No Operation No Operation No Operation No Operat12057 TAMPA ELECTRIC COMPANY F.J. GANNON STATION 646 GB06 0570040 6 No Operation No Operation No Operation No Operation No Operat12061 CITY OF VERO BEACH 693 0610029 1 O/G Steam 

O/G Early 

Retireme

nt 

O/G Early 

Retireme

nt 

O/G Early 

Retireme

nt 

O/G Early 

Retireme

nt 

O/G Ea

Retirem

nt 

12061 CITY OF VERO BEACH 693 3 0610029 3 O/G Steam No Operation No Operation No Operation No Operation No Operat12061 CITY OF VERO BEACH 693 4 0610029 4 O/G Steam No Operation No Operation No Operation No Operation No Operat12063 GULF POWER COMPANY SCHOLZ 642 1 0630014 1 Coal Steam None None Shut Down None None 12063 GULF POWER COMPANY SCHOLZ 642 2 0630014 2 Coal Steam None None Shut Down None None 12073 CITY OF TALLAHASSEE ARVAH B.HOPKINS 688 1 0730003 1 O/G Steam No Operation No Operation No Operation No Operation No Operat12073 CITY OF TALLAHASSEE ARVAH B.HOPKINS 688 2 0730003 4 O/G Steam No Operation No Operation No Operation No Operation No Operat12081 FLORIDA POWER & LIGHT (PMT) MANATEE POWER 6042 PMT1 0810010 1 O/G Steam None No Operation None No Operation None 12081 FLORIDA POWER & LIGHT (PMT) MANATEE POWER 6042 PMT2 0810010 2 O/G Steam None No Operation None No Operation None 12085 FLORIDA POWER & LIGHT (PMR) FPL / MARTIN 6043 PMR1 0850001 1 O/G Steam None None None No Operation None 12085 FLORIDA POWER & LIGHT (PMR) FPL / MARTIN 6043 PMR2 0850001 2 O/G Steam None None None No Operation None 12085 INDIANTOWN COGENERATION, L.P. 50976 GEN1 0850102 1 Coal Steam SCR SCR SCR SCR Scrubb12086 FLORIDA POWER & LIGHT (PCU) CUTLER POWER 610 PCU5 0250001 3 O/G Steam No Operation No Operation No Operation No Operation No Operat
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix I 

284

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

12086 FLORIDA POWER & LIGHT (PCU) CUTLER POWER 610 PCU6 0250001 4 O/G Steam No Operation No Operation No Operation No Operation No Operat12086 FLORIDA POWER & LIGHT (PTF) TURKEY POINT 621 PTP1 0250003 1 O/G Steam None None None No Operation None 12086 FLORIDA POWER & LIGHT (PTF) TURKEY POINT 621 PTP2 0250003 2 O/G Steam None None None No Operation None 12095 

ORLANDO UTILITIES COMMISSION STANTON ENERGY 

564 1 0950137 1 Coal Steam SCR SCR SCR SCR Scrubb

12095 

ORLANDO UTILITIES COMMISSION STANTON ENERGY 

564 2 0950137 2 Coal Steam SCR SCR SCR SCR Scrubb

12099 FLORIDA POWER & LIGHT (PRV) RIVIERA POWE 619 PRV3 0990042 3 O/G Steam None No Operation None No Operation None 12099 FLORIDA POWER & LIGHT (PRV) RIVIERA POWE 619 PRV4 0990042 4 O/G Steam None No Operation None No Operation None 12099 

CITY OF LAKE WORTH UTILITIES TOM G. SMITH 

673 S-1 0990045 7 O/G Steam 

O/G Early 

Retireme

nt 

O/G Early 

Retireme

nt 

O/G Early 

Retireme

nt 

O/G Early 

Retireme

nt 

O/G Ea

Retirem

nt 

12099 

CITY OF LAKE WORTH UTILITIES TOM G. SMITH 

673 S-3 0990045 9 O/G Steam 

O/G Early 

Retireme

nt 

O/G Early 

Retireme

nt 

O/G Early 

Retireme

nt 

O/G Early 

Retireme

nt 

O/G Ea

Retirem

nt 

12101 

PROGRESS ENERGY FLORIDA ANCLOTE 

8048 1 1010017 1 O/G Steam None None None No Operation None 

12101 

PROGRESS ENERGY FLORIDA ANCLOTE 

8048 2 1010017 2 O/G Steam None None None No Operation None 

12103 

PROGRESS ENERGY FLORIDA BARTOW 

634 1 1030011 1 O/G Steam No Operation No Operation None No Operation No Operat

12103 

PROGRESS ENERGY FLORIDA BARTOW 

634 2 1030011 2 O/G Steam 

O/G Early 

Retireme

nt 

O/G Early 

Retireme

nt 

None 

O/G Early 

Retireme

nt 

O/G Ea

Retirem

nt 

12103 

PROGRESS ENERGY FLORIDA BARTOW 

634 3 1030011 3 O/G Steam No Operation No Operation None No Operation No Operat

12105 LAKELAND ELECTRIC CHARLES LARSEN 675 7 1050003 4 O/G Steam O/G Early Retireme nt O/G Early Retireme nt O/G Early Retireme nt O/G Early Retireme nt O/G Ea

Retirem

nt 

12105 LAKELAND ELECTRIC C.D. MCINTOSH, JR. 676 3 1050004 1 Coal Steam None Combine d Cycle None Combine d Cycle None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix I 

285

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

12105 LAKELAND ELECTRIC C.D. MCINTOSH, JR. 676 3 1050004 5 Coal Steam None Combine d Cycle None Combine d Cycle None 12105 LAKELAND ELECTRIC C.D. MCINTOSH, JR. 676 3 1050004 6 Coal Steam SCR SCR SCR SCR Scrubb12107 SEMINOLE ELECTRIC COOPERATIVE, INC. 136 1 1070025 1 Coal Steam SCR SCR SCR SCR Scrubb12107 SEMINOLE ELECTRIC COOPERATIVE, INC. 136 2 1070025 2 Coal Steam SCR SCR SCR SCR Scrubb12111 FT PIERCE UTILITIES AUTHORITY FT PIERCE 658 7 1110003 7 O/G Steam No Operation No Operation No Operation No Operation No Operat12111 FT PIERCE UTILITIES AUTHORITY FT PIERCE 658 8 1110003 8 O/G Steam No Operation No Operation No Operation No Operation No Operat12121 PROGRESS ENERGY FLORIDA SUWANNEE RIVER 638 1 1210003 1 O/G Steam O/G Early Retireme nt O/G Early Retireme nt None O/G Early Retireme nt O/G Ea

Retirem

nt 

12121 PROGRESS ENERGY FLORIDA SUWANNEE RIVER 638 2 1210003 2 O/G Steam O/G Early Retireme nt O/G Early Retireme nt None O/G Early Retireme nt O/G Ea

Retirem

nt 

12121 PROGRESS ENERGY FLORIDA SUWANNEE RIVER 638 3 1210003 3 O/G Steam None No Operation None No Operation None 12127 FLORIDA POWER & LIGHT (PSN) SANFORD POWER 620 PSN3 1270009 1 O/G Steam O/G Early Retireme nt O/G Early Retireme nt O/G Early Retireme nt O/G Early Retireme nt O/G Ea

Retirem

nt 

12127 FLORIDA POWER & LIGHT (PSN) SANFORD POWER 620 PSN4 1270009 2 No Operation No Operation No Operation No Operation No Operat12129 

TALLAHASSEE CITY PURDOM GENERATING STATION 

689 7 1290001 7 O/G Steam No Operation No Operation No Operation No Operation No Operat

13015 GEORGIA POWER COMPANY, BOWEN STEAM-ELECT 703 1BLR 01500011 SG01 Coal Steam SCR SCR SCR SCR None 13015 GEORGIA POWER COMPANY, BOWEN STEAM-ELECT 703 2BLR 01500011 SG02 Coal Steam SCR SCR SCR SCR None 13015 GEORGIA POWER COMPANY, BOWEN STEAM-ELECT 703 3BLR 01500011 SG03 Coal Steam SCR SCR SCR SCR Scrubb13015 GEORGIA POWER COMPANY, BOWEN STEAM-ELECT 703 4BLR 01500011 SG04 Coal Steam SCR SCR SCR SCR Scrubb
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix I 

286

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

13021 ARKWRIGHT 699 1 0002 1 No Operation No Operation No Operation No Operation No Operat13021 ARKWRIGHT 699 2 0002 2 No Operation No Operation No Operation No Operation No Operat13021 ARKWRIGHT 699 3 0002 3 No Operation No Operation No Operation No Operation No Operat13021 ARKWRIGHT 699 4 0002 4 No Operation No Operation No Operation No Operation No Operat13051 SAVANNAH ELECTRIC: KRAFT STEAM 733 1 05100006 SG01 Coal Steam None None None None None 13051 SAVANNAH ELECTRIC: KRAFT STEAM 733 2 05100006 SG02 Coal Steam None None None None None 13051 SAVANNAH ELECTRIC: KRAFT STEAM 733 3 05100006 SG03 Coal Steam None None None SCR None 13051 SAVANNAH ELECTRIC: KRAFT STEAM 733 4 05100006 SG04 O/G Steam No Operation No Operation No Operation No Operation No Operat13051 RIVERSIDE 734 11 05100018 11 O/G Steam None No Operation No Operation No Operation None 13051 RIVERSIDE 734 12 05100018 12 O/G Steam None No Operation No Operation No Operation None 13051 RIVERSIDE 734 4 05100018 4 O/G Steam None None None None None 13051 RIVERSIDE 734 5 05100018 5 O/G Steam None No Operation No Operation No Operation None 13051 RIVERSIDE 734 6 05100018 6 O/G Steam None No Operation No Operation No Operation None 13067 GEORGIA POWER COMPANY, MCDONOUGH STEAM 710 MB1 06700003 SGM1 Coal Steam None None SCR SCR None 13067 GEORGIA POWER COMPANY, MCDONOUGH STEAM 710 MB2 06700003 SGM2 Coal Steam None None SCR SCR None 13077 GEORGIA POWER COMPANY, YATES STEAM-ELECTRIC 728 Y1BR 07700001 SG01 Coal Steam None None None None Scrubb13077 GEORGIA POWER COMPANY, YATES STEAM-ELECTRIC 728 Y2BR 07700001 SG02 Coal Steam None None None None None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix I 

287

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

13077 GEORGIA POWER COMPANY, YATES STEAM-ELECTRIC 728 Y3BR 07700001 SG03 Coal Steam None None None None None 13077 GEORGIA POWER COMPANY, YATES STEAM-ELECTRIC 728 Y4BR 07700001 SG04 Coal Steam None None SCR SCR None 13077 GEORGIA POWER COMPANY, YATES STEAM-ELECTRIC 728 Y5BR 07700001 SG05 Coal Steam None None SCR SCR None 13077 GEORGIA POWER COMPANY, YATES STEAM-ELECTRIC 728 Y6BR 07700001 SG06 Coal Steam None None SCR SCR None 13077 GEORGIA POWER COMPANY, YATES STEAM-ELECTRIC 728 Y7BR 07700001 SG07 Coal Steam None None SCR SCR None 13095 GEORGIA POWER COMPANY, MITCHELL STEAM-ELECTRIC 727 09500002 SG01 No Operation No Operation No Operation No Operation No Operat13095 GEORGIA POWER COMPANY, MITCHELL STEAM-ELECTRIC 727 09500002 SG02 No Operation No Operation No Operation No Operation No Operat13095 GEORGIA POWER COMPANY, MITCHELL STEAM-ELECTRIC 727 3 09500002 SG03 Coal Steam None None None None None 13103 

SAVANNAH ELECTRIC: MCINTOSH STEAM - ELECTRIC 

6124 1 10300003 SG01 Coal Steam None None None SCR None 

13115 

GEORGIA POWER COMPANY, HAMMOND STEAMELECTRIC 708 1 11500003 SG01 Coal Steam None None SCR SCR Scrubb

13115 

GEORGIA POWER COMPANY, HAMMOND STEAMELECTRIC 708 2 11500003 SG02 Coal Steam None None SCR SCR Scrubb

13115 

GEORGIA POWER COMPANY, HAMMOND STEAMELECTRIC 708 3 11500003 SG03 Coal Steam None None SCR SCR Scrubb

13115 

GEORGIA POWER COMPANY, HAMMOND STEAMELECTRIC 708 4 11500003 SG04 Coal Steam SCR SCR SCR SCR Scrubb

13127 

GEORGIA POWER COMPANY, MCMANUS STEAMELECTRIC 715 1 12700004 SG01 O/G Steam No Operation No Operation No Operation No Operation No Operat

13127 

GEORGIA POWER COMPANY, MCMANUS STEAMELECTRIC 715 2 12700004 SG02 O/G Steam No Operation No Operation No Operation No Operation No Operat

13149 GEORGIA POWER COMPANY, WANSLEY STEAM-ELECTRIC 6052 1 14900001 SG01 Coal Steam SCR SCR SCR SCR Scrubb
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix I 

288

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

13149 GEORGIA POWER COMPANY, WANSLEY STEAM-ELECTRIC 6052 2 14900001 SG02 Coal Steam SCR SCR SCR SCR None 13207 GEORGIA POWER COMPANY, SCHERER STEAM-ELECTRIC 6257 1 20700008 SG01 Coal Steam None None None None None 13207 GEORGIA POWER COMPANY, SCHERER STEAM-ELECTRIC 6257 2 20700008 SG02 Coal Steam None None None None None 13207 GEORGIA POWER COMPANY, SCHERER STEAM-ELECTRIC 6257 3 20700008 SG03 Coal Steam None None None None None 13207 GEORGIA POWER COMPANY, SCHERER STEAM-ELECTRIC 6257 4 20700008 SG04 Coal Steam None None None None None 13237 GEORGIA POWER COMPANY, HARLLEE BRANCH 709 1 23700008 SG01 Coal Steam None None SCR SCR None 13237 GEORGIA POWER COMPANY, HARLLEE BRANCH 709 2 23700008 SG02 Coal Steam None None SCR SCR None 13237 GEORGIA POWER COMPANY, HARLLEE BRANCH 709 3 23700008 SG03 Coal Steam None None SCR SCR None 13237 GEORGIA POWER COMPANY, HARLLEE BRANCH 709 4 23700008 SG04 Coal Steam None None SCR SCR None 13297 GENERIC UNIT 9001 13 GSC1 3 ORIS900 113 GSC13 Coal Steam No Operation No Operation SCR SCR No Operat21015 

CINCINNATI GAS & ELECTRIC EAST BEND STAT 

6018 2 2101500029 002 Coal Steam SCR SCR SCR SCR Scrubb

21041 

KENTUCKY UTILITIES CO GHENT GENERATING STATION 

1356 1 2104100010 001 Coal Steam SCR None SCR SCR Scrubb

21041 

KENTUCKY UTILITIES CO GHENT GENERATING STATION 

1356 2 2104100010 002 Coal Steam None None SCR SCR Scrubb

21041 

KENTUCKY UTILITIES CO GHENT GENERATING STATION 

1356 3 2104100010 003 Coal Steam SCR None SCR SCR Scrubb

21041 

KENTUCKY UTILITIES CO GHENT GENERATING STATION 

1356 4 2104100010 004 Coal Steam SCR None SCR SCR Scrubb

21049 EAST KY POWER COOP WILLIAM C DALE PLANT 1385 1 2104900003 001 Coal Steam None None None None None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix I 

289

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

21049 EAST KY POWER COOP WILLIAM C DALE PLANT 1385 2 2104900003 002 Coal Steam None None None None None 21049 EAST KY POWER COOP WILLIAM C DALE PLANT 1385 3 2104900003 003 Coal Steam None None None None None 21049 EAST KY POWER COOP WILLIAM C DALE PLANT 1385 4 2104900003 004 Coal Steam None None None None None 21059 

OWENSBORO MUNICIPAL UTIL ELMER SMITH STATION 

1374 1 2105900027 001 Coal Steam SCR SCR SCR SCR Scrubb

21059 

OWENSBORO MUNICIPAL UTIL ELMER SMITH STATION 

1374 2 2105900027 002 Coal Steam None None SCR SCR Scrubb

21091 WESTERN KY ENERGY CORP COLEMAN STATION 1381 C1 2109100003 001 Coal Steam None None SCR SCR Scrubb21091 WESTERN KY ENERGY CORP COLEMAN STATION 1381 C2 2109100003 002 Coal Steam None None SCR SCR Scrubb21091 WESTERN KY ENERGY CORP COLEMAN STATION 1381 C3 2109100003 003 Coal Steam None None SCR SCR Scrubb21091 GENERIC UNIT 9001 21 GSC2 1 ORIS900 121 GSC21 Coal Steam SCR SCR SCR SCR Scrubb21101 HENDERSON MUN POW & LIGHT 1372 6 2110100012 002 Coal Steam None None None None None 21101 HENDERSON MUN POW & LIGHT 1372 5 2110100012 5 Coal Steam None None None None None 21111 LOU GAS & ELEC, CANE RUN 1363 4 0126 04 Coal Steam None None SCR SCR Scrubb21111 LOU GAS & ELEC, CANE RUN 1363 5 0126 05 Coal Steam None None SCR SCR Scrubb21111 LOU GAS & ELEC, CANE RUN 1363 6 0126 06 Coal Steam None None SCR SCR Scrubb21111 LOU GAS & ELEC, MILL CREEK 1364 1 0127 01 Coal Steam None None SCR SCR Scrubb21111 LOU GAS & ELEC, MILL CREEK 1364 2 0127 02 Coal Steam None None SCR SCR Scrubb
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix I 

290

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

21111 LOU GAS & ELEC, MILL CREEK 1364 3 0127 03 Coal Steam SCR SCR SCR SCR Scrubb21111 LOU GAS & ELEC, MILL CREEK 1364 4 0127 04 Coal Steam SCR SCR SCR SCR Scrubb21127 KENTUCKY POWER CO BIG SANDY PLANT 1353 BSU1 2112700003 001 Coal Steam None SCR SCR SCR None 21127 KENTUCKY POWER CO BIG SANDY PLANT 1353 BSU2 2112700003 002 Coal Steam SCR SCR SCR SCR None 21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 1 2114500006 001 Coal Steam None None None None None 

21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 2 2114500006 002 Coal Steam None None None None None 

21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 3 2114500006 003 Coal Steam None None None None None 

21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 4 2114500006 004 Coal Steam None None None None None 

21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 5 2114500006 005 Coal Steam None None None None None 

21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 6 2114500006 006 Coal Steam None None None None None 

21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 7 2114500006 007 Coal Steam None None None None None 

21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 8 2114500006 008 Coal Steam None None None None None 

21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 9 2114500006 009 Coal Steam None None None None None 

21145 

TVA-ENVIRONMENTAL AFFAIRS SHAWNEE PLANT 

1379 10 2114500006 016 Coal Steam None None None None None 

21161 EAST KY POWER COOP SPURLOCK ST. MAYSVILLE 6041 1 2116100009 001 Coal Steam SCR SCR SCR SCR Scrubb21161 EAST KY POWER COOP SPURLOCK ST. MAYSVILLE 6041 2 2116100009 002 Coal Steam SCR SCR SCR SCR Scrubb
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix I 

291

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

21167 KENTUCKY UTILITIES CO BROWN FACILITY 1355 1 2116700001 001 Coal Steam None None None None Scrubb21167 KENTUCKY UTILITIES CO BROWN FACILITY 1355 2 2116700001 002 Coal Steam None None SCR SCR Scrubb21167 KENTUCKY UTILITIES CO BROWN FACILITY 1355 3 2116700001 003 Coal Steam None None SCR SCR Scrubb21177 KENTUCKY UTILITIES CO GREEN RIVER STATION 1357 4 2117700001 003 Coal Steam None None None None None 21177 KENTUCKY UTILITIES CO GREEN RIVER STATION 1357 5 2117700001 004 Coal Steam None None None None None 21177 TVA PARADISE STEAM PLANT 1378 1 2117700006 001 Coal Steam SCR SCR SCR SCR Scrubb21177 TVA PARADISE STEAM PLANT 1378 2 2117700006 002 Coal Steam SCR SCR SCR SCR Scrubb21177 TVA PARADISE STEAM PLANT 1378 3 2117700006 003 Coal Steam SCR SCR SCR SCR Scrubb21183 WESTERN KY ENERGY CORP WILSON STATION 6823 W1 2118300069 001 Coal Steam SCR SCR SCR SCR Scrubb21199 EAST KY POWER COOP JOHN SHERMAN COOPER 1384 1 2119900005 001 Coal Steam None None None None None 21199 EAST KY POWER COOP JOHN SHERMAN COOPER 1384 2 2119900005 002 Coal Steam None SCR SCR SCR None 21223 

LOUISVILLE GAS & ELECTRIC TRIMBLE CO GEN 

6071 1 2122300002 001 Coal Steam SCR SCR SCR SCR Scrubb

21233 HENDERSON STATION 2 1382 H1 2123300001 -A 002 Coal Steam SCR SCR SCR SCR Scrubb21233 HENDERSON STATION 2 1382 H2 2123300001 -A 003 Coal Steam SCR None SCR SCR Scrubb21233 WESTERN KY ENERGY CORP REID 1383 R1 2123300001 -B 001 Coal Steam None None None None None 21233 WESTERN KY ENERGY CORP GREEN STATION 6639 G1 2123300052 001 Coal Steam None None SCR SCR Scrubb
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

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292

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

21233 WESTERN KY ENERGY CORP GREEN STATION 6639 G2 2123300052 002 Coal Steam None None SCR SCR Scrubb21239 KENTUCKY UTILITIES TYRONE FACILITY 1361 5 2123900001 005 Coal Steam None None None None None 28011 ENTERGY MISSISSIPPI INC, DELTA PLANT 2051 1 2801100031 001 O/G Steam None O/G Early Retireme nt None O/G Early Retireme nt None 28011 ENTERGY MISSISSIPPI INC, DELTA PLANT 2051 2801100031 002 None O/G Early Retireme nt None O/G Early Retireme nt None 28011 ENTERGY MISSISSIPPI INC, DELTA PLANT 2051 2 2801100031 003 O/G Steam None O/G Early Retireme nt None O/G Early Retireme nt None 28011 ENTERGY MISSISSIPPI INC, DELTA PLANT 2051 2801100031 004 None O/G Early Retireme nt None O/G Early Retireme nt None 28019 

CHOCTAW GENERATION LLP, RED HILLS GENERATING 

55076 AA001 2801900011 001A Coal Steam SCR SCR SCR SCR Scrubb

28019 

CHOCTAW GENERATION LLP, RED HILLS GENERATING 

55076 AA002 2801900011 001B 

28035 

MISSISSIPPI POWER COMPANY, PLANT EATON 

2046 2803500038 001 O/G Steam No Operation No Operation No Operation No Operation No Operat

28035 

MISSISSIPPI POWER COMPANY, PLANT EATON 

2046 2803500038 002 O/G Steam No Operation No Operation No Operation No Operation No Operat

28035 

MISSISSIPPI POWER COMPANY, PLANT EATON 

2046 2803500038 003 O/G Steam No Operation No Operation No Operation No Operation No Operat

28047 

MISSISSIPPI POWER COMPANY, PLANT JACK WATSON 

2049 1 2804700055 001 O/G Steam No Operation No Operation No Operation No Operation No Operat

28047 

MISSISSIPPI POWER COMPANY, PLANT JACK WATSON 

2049 2 2804700055 002 O/G Steam No Operation No Operation No Operation No Operation No Operat

28047 

MISSISSIPPI POWER COMPANY, PLANT JACK WATSON 

2049 3 2804700055 003 O/G Steam No Operation No Operation No Operation No Operation No Operat

28047 

MISSISSIPPI POWER COMPANY, PLANT JACK WATSON 

2049 4 2804700055 004 Coal Steam None SCR SCR SCR None 
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293

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

28047 

MISSISSIPPI POWER COMPANY, PLANT JACK WATSON 

2049 5 2804700055 005 Coal Steam None SCR SCR SCR None 

28049 ENTERGY MISSISSIPPI INC, REX BROWN PLANT 2053 4 2804900112 001 O/G Steam None O/G Early Retireme nt None O/G Early Retireme nt None 28049 ENTERGY MISSISSIPPI INC, REX BROWN PLANT 2053 3 2804900112 002 O/G Steam None O/G Early Retireme nt None O/G Early Retireme nt None 28059 

MISSISSIPPI POWER COMPANY, PLANT DANIEL 

6073 1 2805900090 001 Coal Steam None SCR SCR SCR None 

28059 

MISSISSIPPI POWER COMPANY, PLANT DANIEL 

6073 2 2805900090 002 Coal Steam None SCR SCR SCR None 

28067 

MOSELLE SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION 

2070 1 2806700035 001 O/G Steam No Operation No Operation No Operation No Operation No Operat

28067 

MOSELLE SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION 

2070 2 2806700035 002 O/G Steam No Operation No Operation No Operation No Operation No Operat

28067 

MOSELLE SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION 

2070 3 2806700035 003 O/G Steam No Operation No Operation No Operation No Operation No Operat

28073 

RD MORROW SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION 

6061 1 2807300021 001 Coal Steam None None SCR SCR Scrubb

28073 

RD MORROW SOUTH MISSISSIPPI ELECTRIC POWER ASSOCIATION 

6061 2 2807300021 002 Coal Steam None None SCR SCR Scrubb

28075 

MISSISSIPPI POWER COMPANY, PLANT SWEATT 

2048 1 2807500032 001 O/G Steam No Operation No Operation No Operation No Operation No Operat

28075 

MISSISSIPPI POWER COMPANY, PLANT SWEATT 

2048 2 2807500032 002 O/G Steam No Operation No Operation No Operation No Operation No Operat

28083 GREENWOOD UTILITIES, HENDERSON STATION 2062 H1 2808300048 001 O/G Steam None None None None No Operat28083 GREENWOOD UTILITIES, HENDERSON STATION 2062 H3 2808300048 003 O/G Steam None None None None No Operat28149 ENTERGY MISSISSIPPI INC, BAXTER WILSON 2050 1 2814900027 001 O/G Steam None O/G Early Retireme nt None O/G Early Retireme nt None 
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Appendix I 

294

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

28149 ENTERGY MISSISSIPPI INC, BAXTER WILSON 2050 2 2814900027 002 O/G Steam None O/G Early Retireme nt None O/G Early Retireme nt None 28151 ENTERGY MISSISSIPPI INC, GERALD ANDRUS 8054 1 2815100048 001 O/G Steam None No Operation None No Operation None 28163 YAZOO CITY PUBLIC SERVICE COMMISSION 2067 3 2816300005 001 O/G Steam O/G Early Retireme nt O/G Early Retireme nt O/G Early Retireme nt O/G Early Retireme nt O/G Ea

Retirem

nt 

37017 ELIZABETHTOWN POWER, LLC 10380 UNIT1 3701700043 G-17A Coal Steam None None None None None 37017 ELIZABETHTOWN POWER, LLC 10380 UNIT2 3701700043 G-17B None None None None None 37019 

COGENTRIX OF NORTH CAROLINA INC - SOUTHPORT 

10378 GEN1 3701900067 G-29 Coal Steam None None None None None 

37019 

COGENTRIX OF NORTH CAROLINA INC - SOUTHPORT 

10378 GEN2 3701900067 G-30 Coal Steam None None None None None 

37021 CAROLINA POWER & LIGHT ASHEVILLE STEAM 2706 1 628 1 Coal Steam SCR SCR SCR SCR Scrubb37021 CAROLINA POWER & LIGHT ASHEVILLE STEAM 2706 2 628 2 Coal Steam SCR SCR SCR SCR Scrubb37025 KANNAPOLIS ENERGY PARTNERS LLC 3702500113 G-2 Coal Steam None None None None None 37025 KANNAPOLIS ENERGY PARTNERS LLC 3702500113 G-3 Coal Steam None None None None None 37035 

DUKE ENERGY CORPORATION MARSHALL STEAM 

2727 3 3703500073 G-1 Coal Steam SNCR SCR SCR SCR Scrubb

37035 

DUKE ENERGY CORPORATION MARSHALL STEAM 

2727 4 3703500073 G-2 Coal Steam SNCR SCR SCR SCR Scrubb

37035 

DUKE ENERGY CORPORATION MARSHALL STEAM 

2727 1 3703500073 G-4 Coal Steam SNCR SCR SCR SCR Scrubb

37035 

DUKE ENERGY CORPORATION MARSHALL STEAM 

2727 2 3703500073 G-5 Coal Steam SNCR SCR SCR SCR Scrubb

37037 

PROGRESS ENERGY CAROLINAS CAPE FEAR 

2708 5 3703700063 G-1 Coal Steam SNCR SNCR SNCR SNCR None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix I 

295

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

37037 

PROGRESS ENERGY CAROLINAS CAPE FEAR 

2708 6 3703700063 G-2 Coal Steam SNCR SNCR SNCR SNCR None 

37045 GENERIC UNIT 9001 37 GSC3 7 ORIS900 137 GSC37 Coal Steam No Operation No Operation SCR SCR No Operat37055 GENERIC UNIT 9002 37 GSC3 7 ORIS900 237 GSC37 Coal Steam No Operation No Operation SCR SCR No Operat37055 GENERIC UNIT 9003 37 GSC3 7 ORIS900 337 GSC37 Coal Steam No Operation No Operation SCR SCR No Operat37061 GENERIC UNIT 9004 37 GSC3 7 ORIS900 437 GSC37 Coal Steam No Operation No Operation SCR SCR No Operat37083 GENERIC UNIT 9005 37 GSC3 7 ORIS900 537 GSC37 Coal Steam No Operation No Operation SCR SCR No Operat37083 GENERIC UNIT 9006 37 GSC3 7 ORIS900 637 GSC37 Coal Steam No Operation No Operation SCR SCR No Operat37071 

DUKE ENERGY CORPORATION ALLEN STEAM 

2718 1 3707100039 G-14 Coal Steam SNCR SNCR SNCR SNCR Scrubb

37071 

DUKE ENERGY CORPORATION ALLEN STEAM 

2718 2 3707100039 G-15 Coal Steam SNCR SNCR SNCR SNCR Scrubb

37071 

DUKE ENERGY CORPORATION ALLEN STEAM 

2718 3 3707100039 G-16 Coal Steam SNCR SCR SCR SCR Scrubb

37071 

DUKE ENERGY CORPORATION ALLEN STEAM 

2718 4 3707100039 G-17 Coal Steam SNCR SCR SCR SCR Scrubb

37071 

DUKE ENERGY CORPORATION ALLEN STEAM 

2718 5 3707100039 G-18 Coal Steam SNCR SCR SCR SCR Scrubb

37071 

DUKE ENERGY CORPORATION RIVERBEND STEAM 

2732 7 3707100040 G-17 Coal Steam SNCR SNCR SNCR SNCR None 

37071 

DUKE ENERGY CORPORATION RIVERBEND STEAM 

2732 8 3707100040 G-18 Coal Steam SNCR SNCR SNCR SNCR None 

37071 

DUKE ENERGY CORPORATION RIVERBEND STEAM 

2732 9 3707100040 G-19 Coal Steam SNCR SNCR SNCR SNCR None 

37071 

DUKE ENERGY CORPORATION RIVERBEND STEAM 

2732 10 3707100040 G-20 Coal Steam SNCR SNCR SNCR SNCR None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

Appendix I 

296

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

37083 ROANOKE VALLEY ENERGY FACILITY 3708300174 G-27 Coal Steam None None None None None 37083 ROANOKE VALLEY ENERGY FACILITY 3708300174 G-7 Coal Steam None None None None None 37129 L V SUTTON STEAM ELECTRIC PLANT 2713 1 3712900036 G-187 Coal Steam None SNCR SNCR SNCR None 37129 L V SUTTON STEAM ELECTRIC PLANT 2713 2 3712900036 G-188 Coal Steam None SCR SCR SCR None 37129 L V SUTTON STEAM ELECTRIC PLANT 2713 3 3712900036 G-189 Coal Steam None SCR SCR SCR None 37145 CP&L - ROXBORO STEAM ELECTRIC PLANT 2712 1 3714500029 G-29 Coal Steam SCR SCR SCR SCR Scrubb37145 CP&L - ROXBORO STEAM ELECTRIC PLANT 2712 2 3714500029 G-30 Coal Steam SCR SCR SCR SCR Scrubb37145 CP&L - ROXBORO STEAM ELECTRIC PLANT 2712 3A 3714500029 G-35A Coal Steam SCR SCR SCR SCR Scrubb37145 CP&L - ROXBORO STEAM ELECTRIC PLANT 2712 3B 3714500029 G-35B Coal Steam SCR SCR SCR SCR Scrubb37145 CP&L - ROXBORO STEAM ELECTRIC PLANT 2712 4A 3714500029 G-36A Coal Steam SCR SCR SCR SCR Scrubb37145 CP&L - ROXBORO STEAM ELECTRIC PLANT 2712 4B 3714500029 G-36B Coal Steam SCR SCR SCR SCR Scrubb37145 CP&L - MAYO FACILITY 6250 1A 3714500045 G-46A Coal Steam SCR SCR SCR SCR Scrubb37145 CP&L - MAYO FACILITY 6250 1B 3714500045 G-46B Coal Steam SCR SCR SCR SCR Scrubb37155 

PROGRESS ENERGY CAROLINAS, INC., W.H. WEATHERSPOON 

2716 1 3715500147 G-24 Coal Steam None SNCR SNCR SNCR None 

37155 

PROGRESS ENERGY CAROLINAS, INC., W.H. WEATHERSPOON 

2716 2 3715500147 G-25 Coal Steam None SNCR SNCR SNCR None 

37155 

PROGRESS ENERGY CAROLINAS, INC., W.H. WEATHERSPOON 

2716 3 3715500147 G-26 Coal Steam None SNCR SNCR SNCR None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

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297

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

37155 LUMBERTON POWER, LLC 10382 UNIT1 3715500166 G-17A Coal Steam None None None None None 37155 LUMBERTON POWER, LLC 10382 UNIT2 3715500166 G-17B None None None None None 37157 DUKE ENERGY CORP DAN RIVER STEAM 2723 3 3715700015 G-21 Coal Steam None SNCR SNCR SNCR None 37157 DUKE ENERGY CORP DAN RIVER STEAM 2723 1 3715700015 G-22 Coal Steam None SNCR SNCR SNCR None 37157 DUKE ENERGY CORP DAN RIVER STEAM 2723 2 3715700015 G-23 Coal Steam None SNCR SNCR SNCR None 37159 

DUKE ENERGY CORPORATION BUCK STEAM 

2720 5 3715900004 G-1 Coal Steam None SNCR SNCR SNCR None 

37159 

DUKE ENERGY CORPORATION BUCK STEAM 

2720 6 3715900004 G-2 Coal Steam None SNCR SNCR SNCR None 

37159 

DUKE ENERGY CORPORATION BUCK STEAM 

2720 7 3715900004 G-3 Coal Steam SNCR SNCR SNCR SNCR None 

37159 

DUKE ENERGY CORPORATION BUCK STEAM 

2720 8 3715900004 G-4 Coal Steam SNCR SNCR SNCR SNCR None 

37159 

DUKE ENERGY CORPORATION BUCK STEAM 

2720 9 3715900004 G-5 Coal Steam SNCR SNCR SNCR SNCR None 

37161 

DUKE ENERGY CORPORATION CLIFFSIDE STEAM 

2721 1 3716100028 G-82 Coal Steam None SNCR SNCR SNCR None 

37161 

DUKE ENERGY CORPORATION CLIFFSIDE STEAM 

2721 2 3716100028 G-83 Coal Steam None SNCR SNCR SNCR None 

37161 

DUKE ENERGY CORPORATION CLIFFSIDE STEAM 

2721 3 3716100028 G-84 Coal Steam None SNCR SNCR SNCR None 

37161 

DUKE ENERGY CORPORATION CLIFFSIDE STEAM 

2721 4 3716100028 G-85 Coal Steam None SNCR SNCR SNCR None 

37161 

DUKE ENERGY CORPORATION CLIFFSIDE STEAM 

2721 5 3716100028 G-86 Coal Steam SCR SCR SCR SCR None 

37161 DUKE ENERGY CORPORATION 2721 6 3716100028 G-87 Coal Steam No Operation Not in IPM SCR Not in IPM No Operat
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

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APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

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FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

CLIFFSIDE STEAM 

37161 

DUKE ENERGY CORPORATION CLIFFSIDE STEAM 

2721 7 3716100028 G-88 No Operation Not in IPM No Operation Not in IPM No Operat

37169 DUKE ENERGY CORP BELEWS CREEK STEAM 8042 1 3716900004 G-17 Coal Steam SCR SCR SCR SCR Scrubb37169 DUKE ENERGY CORP BELEWS CREEK STEAM 8042 2 3716900004 G-18 Coal Steam SCR SCR SCR SCR Scrubb37191 PROGRESS ENERGY F LEE PLANT 2709 1 3719100017 G-2 Coal Steam None SNCR SNCR SNCR None 37191 PROGRESS ENERGY F LEE PLANT 2709 2 3719100017 G-3 Coal Steam None SNCR SNCR SNCR None 37191 PROGRESS ENERGY F LEE PLANT 2709 3 3719100017 G-4 Coal Steam None SCR SCR SCR None 45003 SCE&G:URQUHART 3295 URQ3 0080-0011 003 Coal Steam None None None None None 45003 SCE&G:SRS AREA D 0080-0044 001 Coal Steam None None None None None 45003 SCE&G:SRS AREA D 0080-0044 002 None None None None 45003 SCE&G:SRS AREA D 0080-0044 003 None None None None 45003 SCE&G:SRS AREA D 0080-0044 004 None None None None 45007 DUKE ENERGY:LEE 3264 1 0200-0004 001 Coal Steam None None None None None 45007 DUKE ENERGY:LEE 3264 2 0200-0004 002 Coal Steam None None None None None 45007 DUKE ENERGY:LEE 3264 3 0200-0004 003 Coal Steam None None None None None 45015 SANTEE COOPER JEFFERIES 3319 1 0420-0003 001 O/G Steam No Operation No Operation None No Operation No Operat
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

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299

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

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FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

45015 SANTEE COOPER JEFFERIES 3319 2 0420-0003 002 O/G Steam No Operation No Operation None No Operation No Operat45015 SANTEE COOPER JEFFERIES 3319 3 0420-0003 003 Coal Steam None SCR None SCR None 45015 SANTEE COOPER JEFFERIES 3319 4 0420-0003 004 Coal Steam None None None None None 45015 SCE&G:WILLIAMS 3298 WIL1 0420-0006 001 Coal Steam SCR SCR SCR SCR None 45015 SANTEE COOPER CROSS 130 1 0420-0030 001 Coal Steam SCR SCR SCR SCR Scrubb

Upgra

45015 SANTEE COOPER CROSS 130 2 0420-0030 002 Coal Steam SCR SCR SCR SCR Scrubb

Upgra

45015 SANTEE COOPER CROSS 130 3 0420-0030 3 Coal Steam SCR SCR SCR SCR Scrubb45015 SANTEE COOPER CROSS 130 4 0420-0030 4 Coal Steam SCR SCR SCR SCR Scrubb45029 SCE&G:CANADYS 3280 CAN1 0740-0002 001 Coal Steam None None None None None 45029 SCE&G:CANADYS 3280 CAN2 0740-0002 002 Coal Steam None None None None None 45029 SCE&G:CANADYS 3280 CAN3 0740-0002 003 Coal Steam None None None None Scrubb45031 PROGRESS ENERGY ROBINSON STATION 3251 1 0820-0002 001 Coal Steam None None None None None 45043 SANTEE COOPER WINYAH 6249 1 1140-0005 001 Coal Steam SCR SCR SCR SCR Scrubb45043 SANTEE COOPER WINYAH 6249 2 1140-0005 002 Coal Steam SCR SCR SCR SCR Scrubb45043 SANTEE COOPER WINYAH 6249 3 1140-0005 003 Coal Steam SCR SCR SCR SCR Scrubb

Upgra

45043 SANTEE COOPER WINYAH 6249 4 1140-0005 004 Coal Steam SCR SCR SCR SCR Scrubb

Upgra

45051 SANTEE COOPER GRAINGER 3317 1 1340-0003 001 Coal Steam None None None None None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

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300

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

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FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

45051 SANTEE COOPER GRAINGER 3317 2 1340-0003 002 Coal Steam None None None None None 45063 SCE&G:MCMEEKIN 3287 MCM1 1560-0003 001 Coal Steam None None None None None 45063 SCE&G:MCMEEKIN 3287 MCM2 1560-0003 002 Coal Steam None None None None None 45075 SCE&G:COPE 7210 COP1 1860-0044 001 Coal Steam None None None None Scrubb45079 SCE&G:WATEREE 3297 WAT1 1900-0013 001 Coal Steam SCR SCR SCR SCR Scrubb45079 SCE&G:WATEREE 3297 WAT2 1900-0013 002 Coal Steam SCR SCR SCR SCR Scrubb45029 GENERIC UNIT 9001 45 GSC4 5 ORIS900 145 GSC45 Coal Steam No Operation No Operation SCR SCR No Operat45031 GENERIC UNIT 9002 45 GSC4 5 ORIS900 245 GSC45 Coal Steam No Operation No Operation SCR SCR No Operat45031 GENERIC UNIT 9003 45 GSC4 5 ORIS900 345 GSC45 Coal Steam No Operation No Operation SCR SCR No Operat45039 GENERIC UNIT 9004 45 GSC4 5 ORIS900 445 GSC45 Coal Steam No Operation No Operation SCR SCR No Operat45043 GENERIC UNIT 9005 45 GSC4 5 ORIS900 545 GSC45 Coal Steam No Operation No Operation Cross Unit 4 SCR No Operat47001 TVA BULL RUN FOSSIL PLANT 3396 1 0009 001 Coal Steam SCR SCR SCR SCR Scrubb47073 TVA JOHN SEVIER FOSSIL PLANT 3405 1 0007 001 Coal Steam None None SCR SCR None 47073 TVA JOHN SEVIER FOSSIL PLANT 3405 2 0007 002 Coal Steam None None SCR SCR None 47073 TVA JOHN SEVIER FOSSIL PLANT 3405 3 0007 003 Coal Steam None None SCR SCR None 47073 TVA JOHN SEVIER FOSSIL PLANT 3405 4 0007 004 Coal Steam None None SCR SCR None 47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 1 0011 001 Coal Steam None SCR SCR SCR None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

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APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

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FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 2 0011 002 Coal Steam None SCR SCR SCR None 47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 3 0011 003 Coal Steam None SCR SCR SCR None 47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 4 0011 004 Coal Steam None SCR SCR SCR None 47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 5 0011 005 Coal Steam None SCR SCR SCR None 47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 6 0011 006 Coal Steam None SCR SCR SCR None 47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 7 0011 007 Coal Steam None SCR SCR SCR None 47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 8 0011 008 Coal Steam None SCR SCR SCR None 47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 9 0011 009 Coal Steam None SCR SCR SCR None 47085 TVA JOHNSONVILLE FOSSIL PLANT 3406 10 0011 010 Coal Steam None SCR SCR SCR None 47145 TVA KINGSTON FOSSIL PLANT 3407 1 0013 001 Coal Steam SCR SCR SCR SCR None 47145 TVA KINGSTON FOSSIL PLANT 3407 2 0013 002 Coal Steam SCR SCR SCR SCR None 47145 TVA KINGSTON FOSSIL PLANT 3407 3 0013 003 Coal Steam SCR SCR SCR SCR None 47145 TVA KINGSTON FOSSIL PLANT 3407 4 0013 004 Coal Steam SCR SCR SCR SCR None 47145 TVA KINGSTON FOSSIL PLANT 3407 5 0013 005 Coal Steam SCR SCR SCR SCR None 47145 TVA KINGSTON FOSSIL PLANT 3407 6 0013 006 Coal Steam SCR SCR SCR SCR None 47145 TVA KINGSTON FOSSIL PLANT 3407 7 0013 007 Coal Steam SCR SCR SCR SCR None 47145 TVA KINGSTON FOSSIL PLANT 3407 8 0013 008 Coal Steam SCR SCR SCR SCR None 
Documentation of the Base G2 and Best & Final 2002 Base Year, 2009 and 2018 Emission Inventories

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APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

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ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

47145 TVA KINGSTON FOSSIL PLANT 3407 9 0013 009 Coal Steam SCR None SCR SCR None 47157 ALLEN FOSSIL PLANT 3393 1 00528 Boilr1 Coal Steam SCR SCR SCR SCR None 47157 ALLEN FOSSIL PLANT 3393 2 00528 Boilr2 Coal Steam SCR SCR SCR SCR None 47157 ALLEN FOSSIL PLANT 3393 3 00528 Boilr3 Coal Steam SCR SCR SCR SCR None 47161 TVA CUMBERLAND FOSSIL PLANT 3399 1 0011 001 Coal Steam SCR SCR SCR SCR Scrubb47161 TVA CUMBERLAND FOSSIL PLANT 3399 2 0011 002 Coal Steam SCR SCR SCR SCR Scrubb47165 TVA GALLATIN FOSSIL PLANT 3403 1 0025 001 Coal Steam None None None None None 47165 TVA GALLATIN FOSSIL PLANT 3403 2 0025 002 Coal Steam None None None None None 47165 TVA GALLATIN FOSSIL PLANT 3403 3 0025 003 Coal Steam None None None None None 47165 TVA GALLATIN FOSSIL PLANT 3403 4 0025 004 Coal Steam None None None None None 51031 DOMINION - ALTAVISTA POWER STATION 10773 1 00156 1 Coal Steam SNCR SNCR SNCR SNCR Scrubb51031 DOMINION - ALTAVISTA POWER STATION 10773 2 00156 2 0 0 0 0 0 51041 DOMINION - CHESTERFIELD POWER STATION 3797 3 00002 3 Coal Steam None None None None None 51041 DOMINION - CHESTERFIELD POWER STATION 3797 4 00002 4 Coal Steam SCR None SCR SCR None 51041 DOMINION - CHESTERFIELD POWER STATION 3797 5 00002 6 Coal Steam SCR None SCR SCR None 51041 DOMINION - CHESTERFIELD POWER STATION 3797 6 00002 8 Coal Steam SCR SCR SCR SCR Scrubb51065 DOMINION - BREMO POWER STATION 3796 3 00001 1 Coal Steam None None None None None 
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Appendix I 

303

APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

51065 DOMINION - BREMO POWER STATION 3796 4 00001 2 Coal Steam SNCR SNCR SNCR SNCR None 51071 AMERICAN ELECTRIC POWER GLEN LYN 3776 51 00002 1 Coal Steam None None None None None 51071 AMERICAN ELECTRIC POWER GLEN LYN 3776 52 00002 2 Coal Steam None None None None None 51071 AMERICAN ELECTRIC POWER GLEN LYN 3776 6 00002 3 Coal Steam None None None None None 51083 DOMINION - CLOVER POWER STATION 7213 1 00046 1 Coal Steam SNCR SNCR SNCR SNCR Scrubb51083 DOMINION - CLOVER POWER STATION 7213 2 00046 2 Coal Steam SNCR SNCR SNCR SNCR Scrubb51099 BIRCHWOOD POWER PARTNERS, L.P. 54304 1 00012 1 Coal Steam SCR SCR SCR SCR Scrubb51117 Mecklenburg Cogeneration Facility 52007 GEN1 00051 1 Coal Steam None None None None Scrubb51117 Mecklenburg Cogeneration Facility 52007 GEN2 00051 2 Coal Steam None None None None Scrubb51153 DOMINION - POSSUM POINT 3804 3 00002 3 Coal Steam None Combine d Cycle None Combine d Cycle None 51153 DOMINION - POSSUM POINT 3804 4 00002 4 Coal Steam None Combine d Cycle None Combine d Cycle None 51153 DOMINION - POSSUM POINT 3804 5 00002 5 O/G Steam None No Operation None No Operation None 51153 DOMINION - POSSUM POINT 3804 6 00002 Combined Cycle Combine d Cycle Combine d Cycle Combine d Cycle Combine d Cycle Combi

d Cyc

51167 

AMERICAN ELECTRIC POWER CLINCH RIVER PLANT 

3775 1 00003 1 Coal Steam None None SNCR SCR None 

51167 

AMERICAN ELECTRIC POWER CLINCH RIVER PLANT 

3775 2 00003 2 Coal Steam None None SNCR SCR None 

51167 

AMERICAN ELECTRIC POWER CLINCH RIVER PLANT 

3775 3 00003 3 Coal Steam None None SNCR SCR None 
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APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

51175 LG&E Westmoreland Southampton 10774 GEN1 00051 1 Coal Steam None None None None Scrubb51175 LG&E Westmoreland Southampton 00051 2 None None None None 0 51175 LG&E Westmoreland Southampton 00051 4 None None None None 0 51199 DOMINION - YORKTOWN POWER STATION 3809 3 00001 3 O/G Steam SNCR No Operation SNCR No Operation None 51199 DOMINION - YORKTOWN POWER STATION 3809 2 00001 5 Coal Steam SNCR SNCR SNCR SNCR None 51199 DOMINION - YORKTOWN POWER STATION 3809 1 00001 6 Coal Steam SNCR SNCR SNCR SNCR None 51510 POTOMAC RIVER GENERATING STATION 3788 1 00003 1 Coal Steam SNCR 

Coal 

Early 

Retireme

nt 

SNCR 

Coal 

Early 

Retireme

nt 

None 

51510 POTOMAC RIVER GENERATING STATION 3788 2 00003 2 Coal Steam SNCR 

Coal 

Early 

Retireme

nt 

SNCR 

Coal 

Early 

Retireme

nt 

None 

51510 POTOMAC RIVER GENERATING STATION 3788 3 00003 3 Coal Steam SNCR None SNCR None None 51510 POTOMAC RIVER GENERATING STATION 3788 4 00003 4 Coal Steam SNCR None SNCR None None 51510 POTOMAC RIVER GENERATING STATION 3788 5 00003 5 Coal Steam SNCR None SNCR None None 51550 DOMINION - CHESAPEAKE 3803 1 00026 1 Coal Steam SNCR SNCR SNCR SNCR Low 

Coa

51550 DOMINION - CHESAPEAKE 3803 2 00026 2 Coal Steam SNCR SNCR SNCR SNCR Low 

Coa

51550 DOMINION - CHESAPEAKE 3803 3 00026 3 Coal Steam SCR None SCR SCR Low 

Coa

51550 DOMINION - CHESAPEAKE 3803 4 00026 4 Coal Steam SCR None SCR SCR Low 

Coa

51159 GENERIC UNIT 9001 51 GSC5 1 ORIS900 151 GSC51 Coal Steam No Operation No Operation SCR SCR No Operat
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APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

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FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

51167 GENERIC UNIT 9002 51 GSC5 1 ORIS900 251 GSC51 Coal Steam No Operation No Operation SCR SCR No Operat51195 GENERIC UNIT 9002 51 GSC5 1 ORIS900 251 GSC51 Coal Steam No Operation No Operation SCR SCR No Operat51175 GENERIC UNIT 9003 51 GSC5 1 ORIS900 351 GSC51 Coal Steam No Operation No Operation SCR SCR No Operat51175 GENERIC UNIT 9004 51 GSC5 1 ORIS900 451 GSC51 Coal Steam No Operation No Operation SCR SCR No Operat51181 GENERIC UNIT 9005 51 GSC5 1 ORIS900 551 GSC51 Coal Steam No Operation No Operation SCR SCR No Operat54023 MOUNT STORM POWER PLANT 3954 1 0003 001 Coal Steam SCR SCR SCR SCR Scrubb54023 MOUNT STORM POWER PLANT 3954 2 0003 002 Coal Steam SCR SCR SCR SCR Scrubb54023 MOUNT STORM POWER PLANT 3954 3 0003 003 Coal Steam SCR SCR SCR SCR Scrubb54023 NORTH BRANCH POWER STATION 7537 1A 0014 001 Coal Steam None None None None None 54023 NORTH BRANCH POWER STATION 7537 1B 0014 002 Coal Steam None None None None None 54025 WESTERN GREENBRIER 00066 GEN1 Coal Steam No Operation No Operation SCR No Operation No Operat54033 MONONGAHELA POWER CO HARRISON 3944 1 0015 001 Coal Steam SCR SCR SCR SCR Scrubb54033 MONONGAHELA POWER CO HARRISON 3944 2 0015 002 Coal Steam SCR SCR SCR SCR Scrubb54033 MONONGAHELA POWER CO HARRISON 3944 3 0015 003 Coal Steam SCR SCR SCR SCR Scrubb54039 APPALACHIAN POWER KANAWHA RIVER PLANT 3936 1 0006 001 Coal Steam None None SCR SCR None 54039 APPALACHIAN POWER KANAWHA RIVER PLANT 3936 2 0006 002 Coal Steam None None SCR SCR None 54049 MONONGAHELA POWER CO. RIVESVILLE POWER 3945 7 0009 001 Coal Steam None Coal Early None Coal Early None 
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Appendix I 

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APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

Post-Combustion Con

FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

Retireme

nt 

Retireme

nt 

54049 MONONGAHELA POWER CO. RIVESVILLE POWER 3945 8 0009 002 Coal Steam None 

Coal 

Early 

Retireme

nt 

None 

Coal 

Early 

Retireme

nt 

None 

54049 

AMERICAN BITUMINOUS POWER GRANT TOWN PLT 

10151 0026 001 None None None None Scrubb

54049 GRANT TOWN POWER PLANT 10151 GEN1 ORIS10151 GEN1 Coal Steam SNCR None None None Scrubb54051 OHIO POWER MITCHELL PLANT 3948 1 0005 001 Coal Steam SCR SCR SCR SCR Scrubb54051 OHIO POWER MITCHELL PLANT 3948 2 0005 002 Coal Steam SCR SCR SCR SCR Scrubb54051 OHIO POWER KAMMER PLANT 3947 1 0006 001 Coal Steam None SCR SCR SCR None 54051 OHIO POWER KAMMER PLANT 3947 2 0006 002 Coal Steam None SCR SCR SCR None 54051 OHIO POWER KAMMER PLANT 3947 3 0006 003 Coal Steam None SCR SCR SCR None 54053 APPALACHIAN POWER CO. PHILIP SPORN PLANT 3938 11 0001 001 Coal Steam None None SCR SCR None 54053 APPALACHIAN POWER CO. PHILIP SPORN PLANT 3938 21 0001 002 Coal Steam None None SCR SCR None 54053 APPALACHIAN POWER CO. PHILIP SPORN PLANT 3938 31 0001 003 Coal Steam None None SCR SCR None 54053 APPALACHIAN POWER CO. PHILIP SPORN PLANT 3938 41 0001 004 Coal Steam None None SCR SCR None 54053 APPALACHIAN POWER CO. PHILIP SPORN PLANT 3938 51 0001 005 Coal Steam None None SCR SCR None 54053 APPALACHIAN POWER MOUNTAINEER PLANT 6264 1 0009 Coal Steam SCR SCR SCR SCR Scrubb54061 MONONGAHELA POWER CO. FORT MARTIN POWER 3943 1 0001 001 Coal Steam SNCR SNCR SNCR SNCR None 
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Appendix I 

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APPENDIX I: EGU CONTROLS FOR COAL AND OIL/GAS UNITS FOR THE B&F INVENTORY

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FIPS Facility Name 

ORIS 

ID 

BLR 

ID 

SITE 

ID 

UNIT 

ID 

Plant 

Type 

VISTAS 

NOx 

2009 

Controls 

IPM 

NOx 

2009 

Controls 

VISTAS 

NOx 

2018 

Controls 

IPM 

NOx 

2018 

Controls 

VISTA

SO2 20

Contr

54061 MONONGAHELA POWER CO. FORT MARTIN POWER 3943 2 0001 002 Coal Steam SNCR SNCR SNCR SNCR None 54061 MORGANTOWN ENERGY ASSOCIATES 0027 043 None None None None None 54061 MORGANTOWN ENERGY FACILITY 10743 GEN1 ORIS10743 GEN1 Coal Steam None None None None None 54061 LONGVIEW 00134 GEN1 Coal Steam No Operation No Operation SCR No Operation No Operat54061 GENERIC UNIT 9001 54 GSC5 4 ORIS900 154 GSC54 Coal Steam No Operation No Operation No Operation SCR No Operat54073 MONONGAHELA POWER CO. WILLOW ISLAND 3946 1 0004 001 Coal Steam None 

Coal 

Early 

Retireme

nt 

None 

Coal 

Early 

Retireme

nt 

None 

54073 MONONGAHELA POWER CO. WILLOW ISLAND 3946 2 0004 002 Coal Steam None SCR SCR SCR None 54073 

MONONGAHELA POWER CO PLEASANTS POWER STATION 

6004 1 0005 001 Coal Steam SCR SCR SCR SCR Scrubb

Upgra

54073 

MONONGAHELA POWER CO PLEASANTS POWER STATION 

6004 2 0005 002 Coal Steam SCR SCR SCR SCR Scrubb

Upgra

54077 MONONGAHELA POWER CO ALBRIGHT 3942 1 0001 001 Coal Steam None 

Coal 

Early 

Retireme

nt 

Coal 

Early 

Retireme

nt 

Coal 

Early 

Retireme

nt 

None 

54077 MONONGAHELA POWER CO ALBRIGHT 3942 2 0001 002 Coal Steam None 

Coal 

Early 

Retireme

nt 

Coal 

Early 

Retireme

nt 

Coal 

Early 

Retireme

nt 

None 

54077 MONONGAHELA POWER CO ALBRIGHT 3942 3 0001 003 Coal Steam None None SCR SCR None 54079 APPALACHIAN POWER JOHN E AMOS PLANT 3935 1 0006 001 Coal Steam SCR SCR SCR SCR Scrubb54079 APPALACHIAN POWER JOHN E AMOS PLANT 3935 2 0006 002 Coal Steam SCR SCR SCR SCR Scrubb54079 APPALACHIAN POWER JOHN E AMOS PLANT 3935 3 0006 003 Coal Steam SCR SCR SCR SCR Scrubb

Weight of Evidence

E2:  TSD Version IV  042508

“With CAIR”

Link to:

http://www.epa.ohio.gov/portals/27/SIP/Attain/E2_TSD_Version_IV_April_25_2008_FINAL.pdf
Regional Air Quality Analyses for

Ozone, PM2.5, and Regional Haze: 

Final Technical Support Document

April 25, 2008

States of Illinois, Indiana, Michigan, Ohio, and Wisconsin
ii

Table of Contents

Section-Title Page

Executive Summary iii

1.0 Introduction 1

1.1 SIP Requirements 1

1.2 Organization 2

1.3 Technical Work: Overview 3

2.0 Ambient Data Analyses 4

2.1 Ozone 4

2.2 PM2.5 21

2.3 Regional Haze 35

3.0 Air Quality Modeling 46

3.1 Selection of Base Year 46

3.2 Future Years of Interest 46

3.3 Modeling System 47

3.4 Domain/Grid Resolution 47

3.5 Model Inputs: Meteorology 48

3.6 Model Inputs: Emissions 51

3.7 Base Year Modeling Results 60

4.0 Attainment Demonstration for Ozone and PM2.5 71

4.1 Future Year Modeling Results 71

4.2 Supplemental Analyses 82

4.3 Weight of Evidence Determination for Ozone 82

4.4 Weight of Evidence Determination for PM2.5 90

5.0 Reasonable Progress Assessment for Regional Haze 93

5.1 Class I Areas Impacted 93

5.2 Future Year Modeling Results 96

5.3 Weight of Evidence Determination for Regional Haze 104

6.0 Summary 111

7.0 References 114

Appendix I Ozone and PM2.5 Modeling Results

Appendix II Ozone Source Apportionment Modeling Results

Appendix III PM2.5Source Apportionment Modeling Results

Appendix IV Haze Source Apportionment Modeling Results
iii

EXECUTIVE SUMMARY

States in the upper Midwest face a number of air quality challenges. More than 50 counties are 

currently classified as nonattainment for the 8-hour ozone standard and 60 for the fine particle 

(PM2.5) standard (1997 versions). A map of these nonattainment areas is provided in the figure 

below. In addition, visibility impairment due to regional haze is a problem in the larger national 

parks and wilderness areas (i.e., Class I areas). There are 156 Class I areas in the U.S., 

including two in northern Michigan.

Figure i. Current nonattainment counties for ozone (left) and PM2.5 (right)

To support the development of State Implementation Plans (SIPs) for ozone, PM2.5, and 

regional haze in the States of Illinois, Indiana, Michigan, Ohio, and Wisconsin, technical 

analyses were conducted by the Lake Michigan Air Directors Consortium (LADCO), its member 

states, and various contractors. The analyses include preparation of regional emissions 

inventories and meteorological data, evaluation and application of regional chemical transport 

models, and collection and analysis of ambient monitoring data. 

Monitoring data were analyzed to produce a conceptual understanding of the air quality 

problems. Key findings of the analyses include:

Ozone

• Current monitoring data (2005-2007) show about 20 sites in violation of the 8-hour 

ozone standard of 85 parts per billion (ppb). Historical ozone data show a steady 

downward trend over the past 15 years, especially since 2001-2003, due likely to 

federal and state emission control programs.

• Ozone concentrations are strongly influenced by meteorological conditions, with 

more high ozone days and higher ozone levels during summers with above normal 

temperatures.
iv

• Inter- and intra-regional transport of ozone and ozone precursors affects many 

portions of the five states, and is the principal cause of nonattainment in some areas 

far from population or industrial centers. 

PM2.5

• Current monitoring data (2005-2007) show 30 sites in violation of the annual PM2.5

standard of 15 ug/m3. Nonattainment sites are characterized by an elevated 

regional background (about 12 – 14 ug/m3) and a significant local (urban) increment 

(about 2 – 3 ug/m3). Historical PM2.5 data show a slight downward trend since 

deployment of the PM2.5 monitoring network in 1999.

• PM2.5 concentrations are also influenced by meteorology, but the relationship is 

more complex and less well understood compared to ozone.

• On an annual average basis, PM2.5 chemical composition consists mostly of sulfate, 

nitrate, and organic carbon in similar proportions.

Haze

• Current monitoring data (2000-2004) show visibility levels in the Class I areas in 

northern Michigan are on the order of 22 – 24 deciviews. The goal of EPA’s visibility 

program is to achieve natural conditions, which is about 12 deciviews for these 

Class I areas, by the year 2064.

• Visibility impairment is dominated by sulfate and nitrate.

Air quality models were applied to support the regional planning efforts. Two base years were 

used in the modeling analyses: 2002 and 2005. Basecase modeling was conducted to evaluate 

model performance (i.e., assess the model's ability to reproduce observed concentrations). This 

exercise was intended to build confidence in the model prior to its use in examining control 

strategies. Model performance for ozone and PM2.5 was found to be generally acceptable.

Future year strategy modeling was conducted to determine whether existing (“on the books”) 

controls would be sufficient to provide for attainment of the standards for ozone and PM2.5 and if 

not, then what additional emission reductions would be necessary for attainment. Based on the 

modeling and other supplemental analyses, the following general conclusions can be made:

• Existing controls are expected to produce significant improvement in ozone and 

PM2.5 concentrations and visibility levels.

• The choice of the base year affects the future year model projections. A key 

difference between the base years of 2002 and 2005 is meteorology. 2002 was 

more ozone conducive than 2005. The choice of which base year to use as the 

basis for the SIP is a policy decision (i.e., how much safeguard to incorporate).

• Modeling suggests that most sites are expected to meet the current 8-hour ozone 

standard by the applicable attainment date, except for sites in western Michigan 

and, possibly, in eastern Wisconsin and northeastern Ohio.
v

• Modeling suggests that most sites are expected to meet the current PM2.5

standard by the applicable attainment date, except for sites in Detroit, Cleveland, 

and Granite City.

The regional modeling for PM2.5 does not include air quality benefits expected 

from local controls. States are conducting local-scale analyses and will use

these results, in conjunction with the regional-scale modeling, to support their 

attainment demonstrations for PM2.5.

• These findings of residual nonattainment for ozone and PM2.5 are supported by 

current (2005 – 2007) monitoring data which show significant nonattainment in 

the region (e.g., peak ozone design values on the order of 90 – 93 ppb, and peak 

PM2.5 design values on the order of 16 - 17 ug/m3). It is unlikely that sufficient 

emission reductions will occur in the next couple of years to provide for 

attainment at all sites.

• Attainment at most sites by the applicable attainment date is dependent on actual 

future year meteorology (e.g., if the weather conditions are consistent with [or 

less severe than] 2005, then attainment is likely) and actual future year 

emissions (e.g., if the emission reductions associated with the existing controls 

are achieved, then attainment is likely). If either of these conditions is not met, 

then attainment may be less likely.

• Modeling suggests that the new PM2.5 24-hour standard and the new lower 

ozone standard will not be met at several sites, even by 2018, with existing 

controls.

• Visibility levels in a few Class I areas in the eastern U.S. are expected to be 

greater than (less improved than) the uniform rate of visibility improvement 

values in 2018 based on existing controls, including those in northern Michigan 

and some in the northeastern U.S. Visibility levels in many other Class I areas in 

the eastern U.S. are expected to be less than (more improved than) the uniform 

rate of visibility improvement values in 2018. These results, along with 

information on the costs of compliance, time necessary for compliance, energy 

and non air quality environmental impacts of compliance, and remaining useful 

life of existing sources, should be considered by the states in setting reasonable 

progress goals for regional haze.
1

Section 1.0 Introduction

This Technical Support Document summarizes the final air quality analyses conducted by the 

Lake Michigan Directors Consortium (LADCO)1and its contractors to support the development 

of State Implementation Plans (SIPs) for ozone, fine particles (PM2.5 ), and regional haze in the 

States of Illinois, Indiana, Michigan, Ohio, and Wisconsin. The analyses include preparation of 

regional emissions inventories and meteorological modeling data for two base years (2002 and 

2005), evaluation and application of regional chemical transport models, and analysis of 

ambient monitoring data. 

Two aspects of the analyses should be emphasized. First, a regional, multi-pollutant approach 

was taken in addressing ozone, PM2.5, and haze for technical reasons (e.g., commonality in

precursors, emission sources, atmospheric processes, transport influences, and geographic 

areas of concern), and practical reasons (e.g., more efficient use of program resources). 

Furthermore, EPA has consistently encouraged multi-pollutant planning in its rule for the haze 

program (64 FR 35719), and its implementation guidance for ozone (70 FR 71663) and PM2.5

(72 FR 20609). Second, a weight-of-evidence approach was taken in considering the results of 

the various analyses (i.e., two sets of modeling results -- one for a 2002 base year and one for a 

2005 base year -- and ambient data analyses) in order to provide a more robust assessment of 

expected future year air quality.

The report is organized in the following sections. This Introduction provides an overview of 

regulatory requirements and background information on regional planning. Section 2 reviews 

the ambient monitoring data and presents a conceptual model of ozone, PM2.5, and haze for the 

region. Section 3 discusses the air quality modeling analyses, including development of the key 

model inputs (emissions inventory and meteorological data), and basecase model performance 

evaluation. A modeled attainment demonstration for ozone and PM2.5 is presented in Section 4, 

along with relevant data analyses considered as part of the weight-of-evidence determination. 

Section 5 documents the reasonable progress assessment for regional haze, along with

relevant data analyses considered as part of the weight-of-evidence determination. Finally, key 

study findings are reviewed and summarized in Section 6.

1.1 SIP Requirements

For ozone, EPA promulgated designations on April 15, 2004 (69 FR 23858, April 30, 2004). In 

the 5-state region, more than 100 counties were designated as nonattainment.

2

 The

designations became effective on June 15, 2004. SIPs for ozone were due no later than three 

years from the effective date of the nonattainment designations (i.e., by June 2007). The

attainment date for ozone varies as a function of nonattainment classification. For the region, 

the attainment dates are either June 2007 (marginal nonattainment areas), June 2009 (basic 

nonattainment areas), or June 2010 (moderate nonattainment areas).

 

1

 A sub-entity of LADCO, known as the Midwest Regional Planning Organization (MRPO), is responsible 

for the regional haze activities of the multi-state organization.

2

 Based on more recent air quality data, many counties in Indiana, Michigan, and Ohio were 

subsequently redesignated as attainment. As of December 31, 2007, there are 53 counties designated 

as nonattainment in the region.
2

For PM2.5, EPA promulgated designations on December 17, 2004 (70 FR 944, January 5, 2005). 

In the 5-state region, 70 counties were designated as nonattainment.3 The designations became 

effective on April 5, 2005. SIPs for PM2.5 are due no later than three years from the effective 

date of the nonattainment designations (per section 172(b) of the Clean Air Act) (i.e., by April 

2008) and for haze no later than three years after the date on which the Administrator 

promulgated the PM2.5 designations (per the Omnibus Appropriations Act of 2004) (i.e., by 

December 2007). The applicable attainment date for PM2.5 nonattainment areas is five years 

from the date of the nonattainment designation (i.e., by April 2010). 

For haze, the Clean Air Act sets “as a national goal the prevention of any future, and the 

remedying of any existing, impairment of visibility in Class I areas which impairment results from 

manmade air pollution.” There are 156 Class I areas, including two in northern Michigan: Isle 

Royale National Park and Seney National Wildlife Refuge4. EPA’s visibility rule (64 FR 35714, 

July 1, 1999) requires reasonable progress in achieving “natural conditions” by the year 2064. 

As noted above, the first regional haze SIP was due in December 2007 and must address the 

initial 10-year implementation period (i.e., reasonable progress by the year 2018). SIP 

requirements (pursuant to 40 CFR 51.308(d)) include setting reasonable progress goals, 

determining baseline conditions, determining natural conditions, providing a long-term control 

strategy, providing a monitoring strategy (air quality and emissions), and establishing BART 

emissions limitations and associated compliance schedule. 

1.2 Organization

LADCO was established by the States of Illinois, Indiana, Michigan, and Wisconsin in 1989. The 

four states and EPA signed a Memorandum of Agreement (MOA) that initiated the Lake 

Michigan Ozone Study (LMOS) and identified LADCO as the organization to oversee the study. 

Additional MOAs were signed by the States in 1991 (to establish the Lake Michigan Ozone 

Control Program), January 2000 (to broaden LADCO’s responsibilities), and June 2004 (to 

update LADCO’s mission and reaffirm the commitment to regional planning). In March 2004, 

Ohio joined LADCO. LADCO consists of a Board of Directors (i.e., the State Air Directors), a 

technical staff, and various workgroups. The main purposes of LADCO are to provide technical 

assessments for and assistance to its member states, and to provide a forum for its member 

states to discuss regional air quality issues. 

MRPO is a similar entity led by the five LADCO States and involves the federally recognized 

tribes in Michigan and Wisconsin, EPA, and Federal Land Managers (i.e., National Park

Service, U.S. Fish & Wildlife Agency, and U.S. Forest Service). In October 2000, the States of 

Illinois, Indiana, Michigan, Ohio, and Wisconsin signed an MOA that established the MRPO. An 

operating principles document for MRPO, which describe the roles and responsibilities of states, 

tribes, federal agencies, and stakeholders, was issued in March 2001. MRPO has a similar 

purpose as LADCO, but is focused on visibility impairment due to regional haze in the Federal 

Class I areas located inside the borders of the five states, and the impact of emissions from the 

five states on visibility impairment due to regional haze in the Federal Class I areas located

outside the borders of the five states. MRPO works cooperatively with the Regional Planning 

Organizations (RPOs) representing other parts of the country. The RPOs sponsored several

 

3

 USEPA subsequently adjusted the final designations, which resulted in 63 counties in the region being 

designated as nonattainment (70 FR 19844, April 15, 2005).

4

 Although Rainbow Lake in northern Wisconsin is also a Class I area, the visibility rule does not apply

because the Federal Land Manager determined that visibility is not an air quality related value there.